A method for exploiting super heavy oil by non-condensate gas and steam synergic profile control and enhanced VHSD

Abstract

The application discloses a method for exploiting super heavy oil by using non-condensate gas and steam to enhance VHSD, and belongs to the technical field of heavy oil exploitation. The method uses non-condensate gas and steam to replace simple steam flooding, thereby reducing cost. Meanwhile, the injection of non-condensate gas can greatly increase the elastic energy of a formation, and the dissolution of non-condensate gas in crude oil can greatly reduce the viscosity of the crude oil. The combination of the injection of non-condensate gas and steam into a vertical well and the injection of non-condensate gas and steam into a horizontal well can effectively improve the heat connection condition, greatly improve the oil production rate, effectively improve the development efficiency, and improve the crude oil recovery rate. The method is suitable for replacing steam flooding with steam flooding in an old heavy oil area or improving the situation that the injection of steam cannot improve the yield, and improves the development effect.

Description

Technical Field

[0001] This invention belongs to the field of extra-heavy oil extraction technology, specifically involving a method for enhancing VHSD extraction of extra-heavy oil using non-condensate gas synergistic steam regulation. Background Technology

[0002] Currently, VHSD (Vacuum-Hydraulic Surface Depletion) combined oil recovery technology has become a cutting-edge technology for heavy oil development internationally. It mainly involves establishing a combined well network of vertical and horizontal wells, with vertical wells serving as steam injection wells and horizontal wells serving as production wells. The development method involves injecting steam into the vertical wells and then extracting the oil from the horizontal production wells.

[0003] In the field of extra-heavy oil extraction, the conventional VHSD oil production technology uses horizontal wells as production wells, with multiple steam injection vertical wells distributed around and on both sides of the horizontal production wells, forming a many-to-one well network. This allows for good thermal connectivity after steam is injected into the steam injection vertical wells, thereby improving the oil production effect of the horizontal production wells.

[0004] However, after years and multiple rounds of steam injection and steam displacement, some old heavy oil fields often experience low formation pressure, decreased energy, uneven inter-well thermal connectivity, and some production and injection wells lacking effective thermal connectivity, leading to low recovery rates and poor development efficiency. There is an urgent need to propose new measures and adopt new oil production technologies during the succession development process to solve these problems and improve development effectiveness. Summary of the Invention

[0005] The purpose of this section is to outline some aspects of embodiments of the present invention and to briefly describe some preferred embodiments. Simplifications or omissions may be made in this section, as well as in the abstract and title of this application, to avoid obscuring the purpose of these documents; however, such simplifications or omissions should not be construed as limiting the scope of the invention.

[0006] In view of the problems existing in the above and / or prior art, the present invention is proposed.

[0007] Therefore, the purpose of this invention is to overcome the shortcomings of the prior art and provide a method for enhancing VHSD extraction of extra-heavy oil using non-condensate gas synergistic steam regulation.

[0008] To solve the above-mentioned technical problems, the present invention provides the following technical solution: including, in the process of VHSD extraction of extra-heavy oil, injecting non-condensate gas to assist steam regulation and drive, thereby improving the recovery rate of heavy oil;

[0009] The non-condensable gas is a mixture of N2 and CO2 in a volume ratio of 5:1 to 1:5, and the volume ratio of the non-condensable gas to the vapor is 2:1 to 1:2.

[0010] As a preferred embodiment of the method for enhancing VHSD oil extraction using non-condensate gas-assisted steam regulation and drive according to the present invention, the method for determining the parameters of the non-condensate gas-assisted steam regulation and drive includes,

[0011] Based on the technical problems existing in the VHSD extraction of extra-heavy oil, non-condensate gas is injected into the steam regulation step to assist steam regulation. The parameters for non-condensate gas-enhanced VHSD extraction of extra-heavy oil are determined with oil production rate, cumulative oil production and cost as indicators.

[0012] As a preferred embodiment of the non-condensate gas synergistic steam-driven enhanced VHSD extraction method for extra-heavy oil production according to the present invention, the well group for VHSD extraction of extra-heavy oil is configured as four injection vertical wells and one horizontal production well, wherein the horizontal production well is located in the middle of the four injection vertical wells.

[0013] As a preferred embodiment of the non-condensate gas synergistic steam-driven enhanced VHSD extraction method for extra-heavy oil production according to the present invention, the technical problems existing in the VHSD extraction of extra-heavy oil include: the distance between the dynamic fluid level of the horizontal production well and the production layer is <30m, and the temperature at all locations at the bottom of the horizontal production well is >100℃; or the distance between the dynamic fluid level of the horizontal production well and the production layer is <30m, and the temperature at some locations at the bottom of the horizontal production well is <100℃.

[0014] As a preferred embodiment of the non-condensate gas synergistic steam-driven enhanced VHSD extraction method of the present invention, wherein: when the distance between the dynamic fluid level of the horizontal production well and the production layer is <30m, and the temperature at all locations at the bottom of the horizontal production well is >100℃, the production is increased by increasing the gas injection rate.

[0015] As a preferred embodiment of the non-condensate gas synergistic steam regulation and enhanced VHSD extraction method of the present invention, wherein: when the distance between the dynamic fluid level of the horizontal production well and the production layer is <30m, and the temperature at the bottom part of the horizontal production well is <100℃, the production is increased by establishing thermal connectivity.

[0016] As a preferred embodiment of the method for enhancing VHSD (Very Heavy Water Surge) oil extraction using non-condensate gas and steam regulation as described in this invention, the parameters for VHSD oil extraction include the non-condensate gas injection method, gas composition, and the ratio of non-condensate gas to steam under formation conditions.

[0017] As a preferred embodiment of the method for enhancing VHSD oil production using non-condensate gas synergistic steam regulation and drive according to the present invention, wherein: increasing production by increasing the gas injection rate includes,

[0018] Non-condensate gas is injected into the vertical well in conjunction with steam for regulation and drive. The non-condensate gas is a mixture of N2 and CO2 with a volume ratio of 5:1 to 1:5. Under the formation conditions, the volume ratio of non-condensate gas to steam is 2:1 to 1:2.

[0019] 10. As a preferred embodiment of the method for enhancing VHSD oil production through non-condensate gas synergistic steam regulation and drive according to the present invention, wherein: the method of increasing production by establishing thermal connectivity includes,

[0020] Non-condensate gas is injected into vertical wells in low-permeability areas in conjunction with steam regulation and drive. The non-condensate gas is a mixture of N2 and CO2 with a volume ratio of 5:1 to 1:5. Under the formation conditions, the volume ratio of non-condensate gas to steam is 2:1 to 1:2.

[0021] When the oil production rate is less than 2 / 5 of the injection rate, non-condensable gas is injected into the horizontal well to assist steam huff and puff. Production begins after the pressure reaches 1 / 2 of the original formation pressure. When the production rate of the production well is equal to the injection rate, the next round of huff and puff is carried out. The non-condensable gas is a mixture of N2 and CO2 with a volume ratio of 5:1 to 1:5. Under the formation conditions, the volume ratio of non-condensable gas to steam is 2:1 to 1:2.

[0022] As a preferred embodiment of the non-condensate gas synergistic steam regulation and enhanced VHSD extraction method of the present invention, the method is applicable to old heavy oil fields and can effectively improve the heavy oil recovery rate.

[0023] Beneficial effects of this invention:

[0024] This invention provides a method for enhancing VHSD (Vacuum-High-Speed ​​Distillation) for the production of extra-heavy oil using non-condensable gas. It addresses and resolves some technical issues encountered by VHSD technology during reservoir development, scientifically utilizing non-condensable gas to assist steam drive instead of pure steam drive, thus reducing costs. Simultaneously, the injection of non-condensable gas can significantly increase formation elastic energy, and the dissolution of non-condensable gas in crude oil can significantly reduce crude oil viscosity. The combination of non-condensable gas + steam injection in vertical wells and non-condensable gas + steam huff and puff in horizontal wells can effectively improve thermal connectivity, significantly increasing oil production rate, improving development efficiency, and enhancing crude oil recovery. This method is suitable for replacing steam huff and puff with steam drive in old heavy oil fields or for situations where steam injection cannot improve production, thereby improving development effectiveness. Attached Figure Description

[0025] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort. Wherein:

[0026] Figure 1 This is a diagram of the three-dimensional experimental model constructed in Embodiment 1 of the present invention.

[0027] Figure 2 This is a comparison chart of oil production rates in Embodiment 1 and Embodiment 2 of the present invention.

[0028] Figure 3 This is a comparison chart of oil production in Example 1 and Example 2 of the present invention.

[0029] Figure 4 This is a diagram of the three-dimensional experimental model constructed in Embodiment 5 of the present invention.

[0030] Figure 5 This is a comparison chart of oil production rates in Examples 5 and 6 of the present invention.

[0031] Figure 6 This is a comparison chart of oil production in Examples 5 and 6 of the present invention. Detailed Implementation

[0032] To make the above-mentioned objects, features and advantages of the present invention more apparent and understandable, the specific embodiments of the present invention will be described in detail below with reference to the examples in the specification.

[0033] Many specific details are set forth in the following description in order to provide a full understanding of the invention. However, the invention may also be practiced in other ways different from those described herein, and those skilled in the art can make similar extensions without departing from the spirit of the invention. Therefore, the invention is not limited to the specific embodiments disclosed below.

[0034] Secondly, the term "one embodiment" or "embodiment" as used herein refers to a specific feature, structure, or characteristic that may be included in at least one implementation of the present invention. The phrase "in one embodiment" appearing in different places in this specification does not necessarily refer to the same embodiment, nor is it a single or selective embodiment that is mutually exclusive with other embodiments.

[0035] Unless otherwise specified, all chemical reagents used in the embodiments of this invention are commercially available in the art.

[0036] The basic three-dimensional experimental model of vertical-horizontal well groups for VHSD extraction of extra-heavy oil used in this invention is as follows:

[0037] There are a total of 4 injection vertical wells and 1 horizontal production well. The 4 injection vertical wells are located in one corner of the three-dimensional experimental device, and the horizontal production well is located in the middle. The horizontal production well is 30cm long, and the perforation of the 4 injection vertical wells is 15cm long. The horizontal well is 2cm from the bottom of the model and is at the same horizontal height as the bottom of the other 4 vertical wells. The perforation section of the vertical well is 3cm above the top of the model.

[0038] Example 1

[0039] like Figure 1 As shown, this embodiment provides a model to simulate the VHSD (Very Heavy Oil Storage) process for extracting extra-heavy oil. The simulated conditions for VHSD extraction of extra-heavy oil are: the dynamic fluid level of the horizontal production well is less than 30m above the production layer, the temperature at all locations at the bottom of the horizontal production well is >100℃, and there is a problem of low production from the horizontal production well. Specifically:

[0040] A horizontally placed vertical-horizontal well group experimental model was used, with temperature and pressure sensors installed at the bottom of the model cover.

[0041] Prepare quartz sand for filling. When filling the sand, spread the sand evenly, with each layer about 1-2 mm thick, and so on, until the model is filled.

[0042] After filling with sand, cover with the cover plate, open the upper and lower valves, tighten the piston to make the sand layer inside the compacted model reach the designed porosity (28%) and permeability (1500mD), then close the valve;

[0043] Crude oil saturation was carried out. The viscosity of the crude oil used for saturation was 217163 mPa·s at 20℃ (based on the physical properties of the experimental crude oil). The original oil saturation was 0.7, and the total saturation volume was 1200 ml.

[0044] Heat insulation cotton heating pads are placed on the upper part and around the model. The model is then pushed into a constant temperature chamber, heated to 100°C, and the model temperature is kept stable. The back pressure of the horizontal production well is set to 1 MPa.

[0045] Steam is injected into vertical wells, while production is achieved through horizontal wells.

[0046] The total steam injection rate was 5 ml / min, the steam injection temperature was greater than 200℃, and the total amount of injected steam was 750 ml. The flow rate, temperature, and pressure were recorded. At the end of the experiment, the produced fluid was collected and the recovery rate was analyzed.

[0047] Example 2

[0048] The difference between this embodiment and Embodiment 1 is that the steam injection procedure for the vertical well is adjusted, specifically as follows:

[0049] 1) The total steam injection volume is 300ml, the total injection rate is 5ml / min, and the steam injection temperature is greater than 200℃;

[0050] 2) Open the CO2 and N2 valves of the injection well and maintain the total steam injection rate at 5 ml / min. At the same time, inject non-condensable gas with a N2 to CO2 ratio of 5:1 to make the volume ratio of steam and non-condensable gas 1:1 under formation conditions. During the experiment, record the flow rate, temperature and pressure. After the experiment, collect the produced fluid and analyze the recovery rate.

[0051] The simulation results of Example 1 and Example 2 are as follows: Figure 2 , Figure 3 As shown, the first experiment represents the experimental results of Example 1, and the comparative experiment represents the experimental results of Example 2. It can be seen that during the period when only steam is injected, the oil production in the two experiments is roughly the same. However, after injecting non-condensable gas with a N2 to CO2 ratio of 5:1, the production and oil production rate increased significantly.

[0052] Example 3

[0053] This embodiment was used to investigate the effect of the volume ratio of N2 to CO2 on the recovery rate of VHSD for extra-heavy oil extraction. The remaining steps and processes were the same as in Example 2. The optimal extraction scheme was selected by combining the oil production rate, cumulative oil production and the role of non-condensate gas in the formation. The results are shown in Table 1.

[0054] Table 1

[0055]

[0056] Example 4

[0057] This embodiment is used to investigate the effect of the volume ratio of steam and non-condensable gas (N2 and CO2) on the recovery rate of VHSD for extra-heavy oil extraction. The remaining steps and processes are the same as in Example 2. The optimal extraction scheme is selected by combining the oil production rate, cumulative oil production and the role of non-condensable gas in the formation.

[0058] Table 2

[0059]

[0060] As can be seen from Table 1, simply adjusting the volume ratio of injected non-condensate gas has a certain impact on the oil production rate and cumulative oil production. Considering that N2 is insoluble in water, less soluble in oil, and has good expansibility in the reservoir, a higher nitrogen content can save steam injection volume and has greater elastic energy, which can effectively replenish formation pressure. Therefore, the overall effect of a N2 to CO2 volume ratio of 5:1 is the best.

[0061] As can be seen from Table 2, the cumulative oil production and the oil production rate are the highest when the volume ratio of steam to non-condensate gas is 1:1 under formation conditions.

[0062] Example 5

[0063] like Figure 4As shown, this embodiment provides a model to simulate the process of VHSD (Very Heavy Oil Storage) extraction of extra-heavy oil. The simulated conditions for VHSD extraction of extra-heavy oil are: the dynamic fluid level of the horizontal production well is less than 30m above the production layer; the temperature at the bottom of the horizontal production well is less than 100℃; due to the heterogeneity of the reservoir, some injection wells in this VHSD well group have poor heat transfer capacity and cannot establish effective thermal connectivity, resulting in low production from the horizontal production wells. Specifically:

[0064] A horizontally placed vertical-horizontal well group experimental model was used, with temperature and pressure sensors installed at the bottom of the model cover.

[0065] Prepare quartz sand for filling. When filling the sand, spread the sand evenly, with each layer about 1-2 mm thick, and so on, until the model is filled.

[0066] After filling with sand, cover with the cover plate, open the upper and lower valves, tighten the piston, so that the sand layer inside the compaction model reaches the designed porosity (28%), the permeability of Zone 1 (1000mD), and the permeability of Zone 2 (2000mD). Close the valve. The area from the front view to below the dotted line is called Zone 1, and the area from the dotted line to the other side is called Zone 2.

[0067] Crude oil saturation was carried out. The viscosity of the crude oil used for saturation was 217163 mPa·s at 20℃ (based on the physical properties of the experimental crude oil). The original oil saturation was 0.7, and the total saturation volume was 1200 ml.

[0068] Heat insulation cotton heating pads are placed on the upper part and around the model. The model is then pushed into a constant temperature chamber, heated to 100°C, and the model temperature is kept stable. The back pressure of the horizontal production well is set to 1 MPa.

[0069] Steam is injected into vertical wells, while production is achieved through horizontal wells.

[0070] The total steam injection rate was 5 ml / min, the steam injection temperature was greater than 200℃, and the total amount of injected steam was 750 ml. The flow rate, temperature, and pressure were recorded. At the end of the experiment, the produced fluid was collected and the recovery rate was analyzed.

[0071] The temperature sensor detected in real time during the experiment showed that due to the low permeability and temperature below 100℃ in Zone 1 and the temperature above 180℃ in Zone 2, the inconsistent permeability in the horizontal direction of the horizontal production wells led to uneven thermal connectivity, resulting in low production and slow oil production.

[0072] Example 6

[0073] The difference between this embodiment and Embodiment 5 is that the steam injection procedure for the vertical well is adjusted, specifically as follows:

[0074] 1) The total steam injection volume is 300ml, the total injection rate is 5ml / min, and the steam injection temperature is greater than 200℃;

[0075] 2) Open the valves connecting the two vertical wells in Zone 1 (low-permeability zone) to the non-condensate gas container, and simultaneously inject non-condensate gas auxiliary steam with a N2 to CO2 ratio of 2:1, so that the volume ratio of steam and non-condensate gas under formation conditions is 1:2, and maintain the total steam injection rate of the vertical wells at 5ml / min. The total underground volume injection rate of non-condensate gas for the two vertical wells in the low-temperature section (that is, the two vertical wells in low-permeability zone 1) is 10ml / min.

[0076] 3) When the oil production rate is below 2 ml / min, the horizontal well is subjected to non-condensable gas-assisted steam huff and puff, with a steam injection rate of 5 ml / min. Production begins after the steam reaches 1 / 2 of the original formation pressure. Non-condensable gas with a N2 to CO2 ratio of 2:1 is injected to assist the steam huff and puff, so that the volume ratio of steam to non-condensable gas under formation conditions is 1:2. When the production rate of the production well is equal to the injection rate, the next round of huff and puff is carried out. During the experiment, the flow rate, temperature, and pressure are recorded and the produced fluid is collected. After the experiment, the collected liquid is analyzed to analyze the recovery rate.

[0077] After injecting non-condensate gas into two vertical wells in low-permeability zone 1, the temperature in the area rose significantly, from below 100℃ to above 180℃. Figure 5 , Figure 6 As shown, the oil production rate and output have also increased significantly. Through analysis and comparison, it was found that the thermal connectivity of the production well section was uneven under different permeability. By injecting non-condensate gas into the low-permeability area to assist steam drive, the temperature of the low-permeability area increased significantly, thermal connectivity of the production well section was achieved, and production efficiency was improved.

[0078] Example 7

[0079] This embodiment was used to investigate the effect of the volume ratio of N2 to CO2 on the recovery rate of VHSD for extra-heavy oil extraction. The remaining steps and processes were the same as in Example 5. The optimal extraction scheme was selected by combining the oil production rate, cumulative oil production and the role of non-condensate gas in the formation. The results are shown in Table 3.

[0080] Table 3

[0081]

[0082] Example 8

[0083] This embodiment was used to investigate the effect of the volume ratio of steam and non-condensable gas (N2 and CO2) on the recovery rate of VHSD for extra-heavy oil extraction. The remaining steps and processes were the same as in Example 5. The optimal extraction scheme was selected by combining the oil production rate, cumulative oil production and the role of non-condensable gas in the formation. The results are shown in Table 4.

[0084] Table 4

[0085]

[0086] As shown in Table 3, simply adjusting the volume ratio of injected non-condensable gas has a certain impact on oil production rate and cumulative oil production. Considering that CO2 has good miscibility with crude oil and can significantly reduce crude oil viscosity, reduce interfacial tension and increase permeability, injecting non-condensable gas with a volume ratio of N2 to CO2 of 2:1 in low-permeability areas can most effectively establish thermal connectivity in the production well section while replenishing formation energy, thereby maximizing oil production and oil production rate.

[0087] As shown in Table 4, the smaller the volume ratio of steam to non-condensable gas, the more effective it is in establishing thermal connectivity in the production well section, and the higher the oil production and oil production rate.

[0088] In summary, this invention provides a method for enhancing VHSD (Vacuum-High-Speed ​​Dredging) for the production of extra-heavy oil using non-condensable gas. It addresses and resolves some technical issues encountered by VHSD technology during reservoir development. By assessing the production status of horizontal production wells and bottom hole temperatures, different injection methods and non-condensable gas compositions are employed to solve various production problems. This method scientifically utilizes gas price differences to replace simple steam drive, reducing costs. Simultaneously, the injection of non-condensable gas significantly increases formation elasticity, and the dissolution of non-condensable gas in crude oil significantly reduces its viscosity. The combination of non-condensable gas + steam injection in vertical wells and non-condensable gas + steam huff-and-puff injection in horizontal wells effectively improves thermal connectivity, significantly increasing oil production rate and development efficiency, thereby enhancing oil recovery. This method is suitable for replacing steam huff-and-puff injection with steam drive in older heavy oil fields, or for situations where steam injection alone cannot improve production, thus improving development effectiveness.

[0089] It should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention and are not intended to limit it. Although the present invention has been described in detail with reference to preferred embodiments, those skilled in the art should understand that modifications or equivalent substitutions can be made to the technical solutions of the present invention without departing from the spirit and scope of the technical solutions of the present invention, and all such modifications or substitutions should be covered within the scope of the claims of the present invention.

Claims

1. A method for exploiting super heavy oil by non-condensate gas and steam synergistic profile control enhanced VHSD, characterized in that: This includes improving heavy oil recovery by injecting non-condensate gas to assist steam regulation during VHSD extraction of extra-heavy oil; The non-condensable gas is a mixture of N2 and CO2 with a volume ratio of 5:1 to 1:5, and the volume ratio of the non-condensable gas to the steam is 2:1 to 1:

2. The VHSD well group for extracting extra-heavy oil is configured with four injection vertical wells and one horizontal production well, wherein the horizontal production well is located in the middle of the four injection vertical wells. Methods for determining non-condensate gas-assisted steam regulation and drive parameters include: Based on the technical problems existing in the VHSD extraction of extra-heavy oil, non-condensable gas is injected into the steam regulation and drive step to assist steam regulation and drive. The parameters for VHSD extraction of extra-heavy oil enhanced by non-condensable gas are determined with oil production rate, cumulative oil production and cost as indicators. The parameters for VHSD extraction of extra-heavy oil include the injection method of non-condensable gas, gas composition and the ratio of non-condensable gas to steam under formation conditions. The technical problems encountered in the VHSD process for extracting extra-heavy oil include: a. The distance between the dynamic fluid level and the production layer in a horizontal production well is <30m, and the temperature at all locations at the bottom of the horizontal production well is >100℃, or, b. The distance between the dynamic fluid level of the horizontal production well and the production layer is <30m, and the temperature at the bottom of the horizontal production well is <100℃; When the dynamic fluid level of the horizontal production well is less than 30m above the production layer and the temperature at all locations at the bottom of the horizontal production well is greater than 100℃, the production rate is increased by increasing the gas injection rate. That is, non-condensable gas is injected into the vertical well in conjunction with steam for regulation and drive. The non-condensable gas is a mixture of N2 and CO2 with a volume ratio of 5:

1. Under the formation conditions, the volume ratio of non-condensable gas to steam is 2:1 to 1:

2. When the dynamic fluid level of the horizontal production well is less than 30m above the production layer and the temperature at the bottom of the horizontal production well is less than 100℃, the production is increased by establishing thermal connectivity. That is, non-condensable gas is injected into the vertical well in the low-permeability area in conjunction with steam regulation and drive. The non-condensable gas is a mixture of N2 and CO2 with a volume ratio of 2:

1. Under the formation conditions, the volume ratio of non-condensable gas to steam is 2:1 to 1:

2. When the oil production rate is less than 2 / 5 of the injection rate, non-condensable gas is injected into the horizontal well to assist steam huff and puff. Production begins after the pressure reaches 1 / 2 of the original formation pressure. When the production rate of the production well is equal to the injection rate, the next round of huff and puff is carried out. The non-condensable gas is a mixture of N2 and CO2 with a volume ratio of 2:

1. Under the formation conditions, the volume ratio of non-condensable gas to steam is 2:1 to 1:

2.

2. The method for enhancing VHSD extraction of extra-heavy oil using non-condensate gas synergistic steam regulation as described in claim 1, characterized in that: The method described is applicable to old heavy oil fields and can effectively improve the recovery rate of heavy oil.

Images