Oil reservoir exploitation method with reduced steam consumption

Abstract

The present invention discloses a method for oil reservoir exploitation that reduces steam usage. The method is specifically divided into three stages, and the specific methods for each stage are as follows: the first stage: drilling multiple rows of vertical wells, with multiple vertical wells in each row, and then performing steam huff-and-puff production; the second stage: drilling denser horizontal wells on the basis of the vertical wells to perform vertical-horizontal well combination SAGD production; the third stage: using only the vertical wells at the toe end of the horizontal well and the vertical wells at the heel end of the horizontal well as steam injection wells, and shutting down the other vertical wells; by continuously and alternately injecting steam at the vertical wells at the toe end of the horizontal well and the vertical wells at the heel end of the horizontal well, the horizontal wells continue to produce oil. The exploitation method of the present invention can reduce steam usage in the later stages of development. Compared with the conventional operation in the later stages of existing vertical-horizontal well combination SAGD development, the steam usage can be reduced by 10% while maintaining comparable oil production, thereby achieving the purpose of improving economic benefits.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and natural gas development, and in particular to an oil reservoir exploitation method with reduced steam consumption. Background Art

[0002] The vertical-horizontal well combination SAGD has been successfully applied in China for over 15 years. This method is generally used in super-heavy oil and oil sand reservoirs. Generally, production is first carried out through the vertical well steam stimulation method. After a certain number of production cycles, the crude oil recovery rate is only 15% to 20% due to the limitation of the steam stimulation heating radius. However, at this time, the temperature field in the reservoir has basically been formed, and one or more horizontal wells vertically lower than the original vertical wells can be infilled between the original vertical wells. After infilling, the original stimulation vertical wells are converted into steam injection wells. At this time, the reservoir is mainly produced by two driving forces: gravity and pressure difference. This method is generally called vertical-horizontal well combination SAGD. Due to factors such as reservoir heterogeneity, with the continuous injection of steam (through steam injection vertical wells), a dominant channel will be formed between the production horizontal wells and the steam injection vertical wells, which will significantly reduce the utilization rate of steam and lead to a significant decline in economic benefits in the later stages of development.

[0003] Most current SAGD optimization technologies still focus on gravity as the primary driving force and fail to take advantage of the conversion of different injection-production combinations. It is imperative to utilize existing well groups to provide a reservoir production method that reduces steam usage without additional or minimal investment. Summary of the Invention

[0004] The purpose of the present invention is to provide an oil reservoir production method with reduced steam consumption in order to solve the economic benefit problem in the later stage of existing vertical well-horizontal well combination SAGD development.

[0005] In order to achieve the above object, the present invention provides the following technical solutions:

[0006] A method for oil reservoir production with reduced steam usage is provided. The method is specifically divided into three stages, and the specific methods for each stage are as follows:

[0007] The first stage: drilling multiple rows of vertical wells, with multiple vertical wells in each row, and then conducting steam stimulation and extraction;

[0008] The second stage: Based on the vertical wells, infill horizontal wells are drilled to carry out vertical-horizontal well combination SAGD production;

[0009] The third stage: only the vertical wells located at the toe end of the horizontal well and the vertical wells located at the heel end of the horizontal well are used as steam injection wells, and other vertical wells are shut down; by continuously and alternately injecting steam in the vertical wells located at the toe end of the horizontal well and the vertical wells located at the heel end of the horizontal well, the horizontal wells continue to produce oil.

[0010] Preferably, the spacing between adjacent vertical wells in the first stage is 60 to 80 meters.

[0011] Preferably, when the recovery rate of the first stage reaches 15%-20%, the second stage is entered.

[0012] Preferably, in the second phase, based on the vertical well network, the specific process of drilling dense horizontal wells is as follows: a horizontal well is drilled between two adjacent rows of vertical wells, the length of the horizontal well is 300 to 800 meters, and the distance between adjacent horizontal wells and vertical wells is 30 to 50 meters.

[0013] Preferably, when the second phase of mining reaches 8 to 12 years, it enters the third phase.

[0014] Preferably, the distance between the vertical well located at the toe end of the horizontal well and the vertical well located at the heel end of the horizontal well is greater than 300 meters.

[0015] Preferably, the alternating time of the alternating steam injection in the third stage is 3 months to 1 year.

[0016] Preferably, the specific process of alternating steam injection in the third stage is: shut down one group of vertical wells located at the foot end of the horizontal well and one group of vertical wells located at the toe end of the horizontal well, start steam injection in the other group of vertical wells, and the horizontal wells continue to produce. After this process is maintained until the alternation time, the previously closed group of vertical wells is opened for steam injection, the previously steam-injected group of vertical wells is shut down, and the horizontal wells continue to produce, and the production is repeated in this way.

[0017] Preferably, in the third stage, an ICD device is installed on the horizontal well.

[0018] Preferably, the ICD device is an oil-tubing type ICD device.

[0019] The beneficial effects of the present invention are:

[0020] Unlike the displacement direction of the original well network (vertical well to horizontal well), the patented invention utilizes the existing supporting well network, closes some vertical steam injection wells, and uses vertical wells located at the toe and heel ends of the horizontal well to alternately and continuously inject steam according to a certain cycle to achieve injection-production combination conversion, so that a higher pressure difference is formed between the toe and heel ends, thereby changing the original displacement direction for oil recovery (toe to heel, heel to toe and vice versa). Only some vertical steam injection wells are used, which can reduce steam consumption in the later stage of development and achieve the purpose of improving economic benefits. The specific advantages are as follows:

[0021] 1. Leverage the existing well pattern to reduce subsequent investment: The existing supporting vertical and horizontal well pattern consists of vertical wells used for steam stimulation in the early stages of reservoir development. Horizontal wells are added to the existing vertical well pattern to enhance development effectiveness after a certain number of steam stimulation cycles. This creates a vertical-horizontal SAGD well pattern. Leveraging the existing supporting vertical-horizontal well pattern effectively avoids the expense of new drilling in the later stages of SAGD development, reducing investment costs.

[0022] 2. Utilizing some existing vertical wells to improve steam efficiency: In the later stages of vertical-horizontal SAGD development, heterogeneity between the vertical and horizontal wells creates significant high-permeability pathways. This leads to increased ineffective steam circulation in many vertical wells, reducing steam efficiency. This results in increased steam injection rates without significant improvement in oil production, thus reducing economic benefits. This approach reduces the utilization rate of vertical wells by utilizing only a small number of vertical wells at the toe and heel of horizontal wells. Continuous alternating steam injection at a given injection pressure effectively reduces the probability of vertical wells entering the horizontal well through high-permeability pathways, resulting in reduced steam efficiency.

[0023] 3. Reconstruct the reservoir temperature and pressure field through injection-production combination conversion: Continuously and alternately inject steam using vertical wells at the toe and heel of horizontal wells. The alternating steam injection method can be used to alternately change the displacement direction and reconstruct the reservoir temperature and pressure fields.

[0024] 4. By installing a downhole inflow control device (ICD), steam intrusion can be effectively prevented.

[0025] 5. Compared with the conventional operation of the vertical-horizontal well combination SAGD development in the later stage, this method can reduce the steam consumption by 10% under the premise of equivalent oil production. BRIEF DESCRIPTION OF THE DRAWINGS

[0026] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the following is a brief introduction to the drawings required for use in the embodiments or the description of the prior art. Obviously, the drawings described below are some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0027] Figure 1 : Well pattern layout for the second phase;

[0028] Figure 2 : Well pattern layout diagram for the third phase;

[0029] Figure 3 : Schematic diagram of vertical well displacement direction and pressure distribution in the third stage;

[0030] Figure 4: Comparison of cumulative steam injection after 10 years of mining in the second stage of Example 1 and Comparative Example 1;

[0031] Figure 5 : Comparison of cumulative oil production after 10 years of the second phase of production in Example 1 and Comparative Example 1;

[0032] Figure 6 : Comparison diagram of the cumulative gasoline ratios of Example 1 and Comparative Example 1 after 10 years of exploitation in the second stage. DETAILED DESCRIPTION

[0033] To make the objectives, technical solutions, and advantages of the embodiments of the present invention more clear, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without making creative efforts shall fall within the scope of protection of the present invention.

[0034] Example 1

[0035] A method for reducing steam consumption in oil reservoir production is divided into three stages. The specific methods for each stage are as follows:

[0036] The first stage involves drilling multiple rows of vertical wells, with multiple vertical wells in each row, and then conducting steam stimulation and extraction.

[0037] The second stage: On the basis of vertical well pattern, intensified horizontal wells are drilled to carry out vertical-horizontal well combination SAGD mining. The well pattern layout at this time is as follows: Figure 1 As shown: Figure 1 The black circle in the middle is a vertical steam injection well, and the black line is a horizontal well. Figure 1 As can be seen in the figure, the specific arrangement includes multiple rows of vertical wells, each row with multiple vertical wells, and a horizontal well between two adjacent rows of vertical wells. Preferably, the spacing between adjacent vertical wells is approximately 70 meters (60 to 80 meters is optional), the horizontal wells are 300 to 800 meters long, and the spacing between adjacent horizontal wells and vertical wells is 30 to 50 meters (the specific setting of these data requires consideration of many factors, such as geological conditions, engineering capabilities, and reservoir fluid properties, and the range of these data can be fine-tuned during specific configuration).

[0038] The third stage: Only the vertical wells at the toe end of the horizontal well and the vertical wells at the heel end of the horizontal well are used as steam injection wells, and the other vertical wells are shut in. By continuously and alternately injecting steam in the vertical wells at the toe end of the horizontal well and the vertical wells at the heel end of the horizontal well, the horizontal wells continue to produce oil. The well pattern at this time is shown in the figure below. Figure 2 As shown: Figure 2 The black circle in the middle is a vertical steam injection well, and the black line is a horizontal well. Figure 2It can be seen from the figure that no new vertical wells are needed in the third phase. Instead, the vertical wells at the heel and finger ends of the horizontal wells can be used as steam injection wells based on the grid wells in the second phase, and the other vertical wells can be shut in. This can reduce the subsequent investment required for using this method.

[0039] Preferably, the distance between the vertical well at the toe end of the horizontal well and the vertical well at the heel end of the horizontal well is generally greater than 300 meters. Figure 3 As shown, the pressure field of the reservoir changes after the vertical well is alternately displaced from point A to point B. Figure 3 As can be seen, when the alternating flow is implemented in a certain phase, the pressure field in the reservoir changes alternately from point A to point B and then from point B to point A, reconstructing the pressure field distribution within the reservoir. This shift in pressure field distribution ensures that the primary expansion direction of the steam chamber within the reservoir remains alternating from point A to point B and then from point B to point A. This shift reconstructs the temperature field distribution within the reservoir, facilitating the lateral expansion of the steam chamber and improving the sweep efficiency of vertical wells within the reservoir.

[0040] Furthermore, when the recovery rate of the first stage reaches 15%-20%, it enters the second stage.

[0041] Furthermore, when the second phase of mining has been completed for about 10 years (which can be 8 to 12 years), it enters the third phase.

[0042] Furthermore, the alternating steam injection cycle in the third phase typically lasts from three months to one year. If the cycle is too long, steam utilization will be significantly reduced, but if it is too short, the lateral displacement effect will not be apparent. The specific alternation time is dynamic and needs to be determined based on key development indicators during actual field operations. The specific alternation process involves shutting down one of the vertical wells at the foot of the horizontal well and another at the toe of the horizontal well. Steam injection begins in the other vertical well, while the horizontal well continues production. This cycle continues until the alternating time has expired. The previously shut-down vertical well is then opened for steam injection, the previously injected vertical well is shut down, and the horizontal well continues production. This cycle repeats.

[0043] Furthermore, in the third stage, an ICD device is installed in the horizontal well. This reduces the risk of rapid steam intrusion into the horizontal well due to steam injection at the toe and heel ends. Preferably, the ICD device is either a tubing-type ICD or a casing-type ICD. For older horizontal wells, only tubing-type ICDs are suitable. However, if the screen is damaged or there is an opportunity to reinsert the screen, such as when sidetracking is necessary, a casing-type ICD can be used.

[0044] Comparative Example 1

[0045] A method for oil reservoir production is specifically divided into two stages. The specific methods of each stage are as follows:

[0046] The first stage: drilling multiple rows of vertical wells, with multiple vertical wells in each row, and then conducting steam stimulation and extraction;

[0047] The second stage: On the basis of vertical well pattern, intensified horizontal wells are drilled to carry out vertical-horizontal well combination SAGD mining. The well pattern layout at this time is as follows: Figure 1 As shown: Figure 1 The black circle in the middle is a vertical steam injection well, and the black line is a horizontal well. Figure 1 As can be seen, multiple rows of vertical wells are arranged, with multiple vertical wells in each row, and a horizontal well is placed between adjacent rows of vertical wells. Preferably, the spacing between adjacent vertical wells is approximately 70 meters (60 to 80 meters is optional), the horizontal wells are 300 to 800 meters long, and the spacing between adjacent horizontal wells and vertical wells is 30 to 50 meters (the specific setting of these data requires consideration of many factors, such as geological conditions, engineering capabilities, and reservoir fluid properties, and the range of these data can be fine-tuned during specific configuration).

[0048] Furthermore, when the recovery rate of the first stage reaches 15%-20%, it enters the second stage.

[0049] The oil reservoir was mined by using the methods of Example 1 and Comparative Example 1. The mining results of Example 1 and Comparative Example 1 are shown in FIG. Figure 4-6 As shown, the specific analysis Figure 4-6 The following conclusions were drawn:

[0050] Ten years after the second phase of production in Example 1 and Comparative Example 1, the temperature in the reservoir remained essentially the same as the number of alternating rounds. This indicates that using only some vertical wells as steam injection wells can still meet the requirement for continued expansion of the steam chamber. Furthermore, the steam chamber expansion trend in Comparative Example 1 is more lateral, while that in Example 1 is more vertical. During field operations, excessive vertical expansion of the steam chamber often results in more steam heating the overburden, resulting in greater heat loss. The fact that Example 1 is more lateral indicates that the steam is heating the reservoir more, thereby improving the thermal efficiency of the steam.

[0051] Figure 4 This is a comparison chart of the cumulative steam injection after 10 years of mining in the second stage of Example 1 and Comparative Example 1. Figure 4 It can be seen that because the method of Example 1 uses fewer vertical wells, under the premise of constant pressure production, the steam injection amount of Example 1 is significantly lower than the steam injection amount of Comparative Example 1. This shows that the method of Example 1 can significantly reduce the total steam injection amount.

[0052] Figure 5The cumulative oil production comparison chart of Example 1 and Comparative Example 1 after 10 years of second-stage production is shown in Figure 1. Figure 5 It can be seen that the oil production rate in the early stage (after steam stimulation) of Example 1 is slightly better than that of Comparative Example 1. This is mainly because the reservoir has been heated by steam stimulation in the early stage of production. Therefore, although the injection volume in the early stage of Example 1 is lower than that of Comparative Example 1, it can still meet the oil production requirements. Figure 5 It can be seen that the final cumulative oil production of Example 1 and Comparative Example 1 is substantially the same, which also illustrates that Example 1 can effectively guarantee the final oil production of the oil field.

[0053] Figure 6 This is a comparison chart of the cumulative gasoline ratio of Example 1 and Comparative Example 1 after 10 years of second-stage mining. Figure 6 It can be seen that since the steam injection amount of Example 1 is significantly lower than that of Comparative Example 1, while the oil production is basically the same, the gasoline ratio of Example 1 is always lower than that of Comparative Example 1, achieving the "stable oil and reduced steam" effect of this method.

[0054] Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art should understand that they can still modify the technical solutions described in the aforementioned embodiments, or make equivalent replacements for some of the technical features therein; and these modifications or replacements do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for oil reservoir production with reduced steam usage, characterized by: The oil reservoir production method is specifically divided into three stages, and the specific methods of each stage are as follows: The first phase involves drilling multiple rows of vertical wells, with multiple vertical wells in each row, followed by steam stimulation and extraction. The spacing between adjacent vertical wells in the first phase is 60 to 80 meters. When the recovery rate reaches 15% to 20% in the first phase, the second phase begins. The second phase: Based on the vertical wells, infill horizontal wells are drilled to carry out vertical-horizontal well combination SAGD production. The specific process of infilling horizontal wells in the second phase is as follows: a horizontal well is drilled between two adjacent rows of vertical wells. The horizontal well length ranges from 300 to 800 meters, and the spacing between the horizontal well and the adjacent vertical well is 30 to 50 meters. The third stage: only the vertical wells located at the toe end of the horizontal well and the vertical wells located at the heel end of the horizontal well are used as steam injection wells, and the other vertical wells are shut down; by continuously and alternately injecting steam in the vertical wells located at the toe end of the horizontal well and the vertical wells located at the heel end of the horizontal well, the horizontal wells continue to produce oil; the specific process of alternating steam injection in the third stage is: shut down one group of vertical wells among the vertical wells located at the heel end of the horizontal well and the vertical wells located at the toe end of the horizontal well, start steam injection in the other group of vertical wells, and the horizontal wells continue to produce, and maintain this process until the alternation time, then open the group of vertical wells that were previously closed to inject steam, shut down the group of vertical wells that were previously injected with steam, and the horizontal wells still maintain production, and repeat this process.

2. The method for oil reservoir exploitation with reduced steam usage according to claim 1, characterized in that: When the second phase of mining has lasted for 8 to 12 years, it will enter the third phase.

3. The method for oil reservoir production with reduced steam usage according to claim 1, characterized in that: The distance between the vertical well at the toe end of the horizontal well and the vertical well at the heel end of the horizontal well is greater than 300 meters.

4. The method for oil reservoir production with reduced steam usage according to claim 1, characterized in that: The alternating steam injection time in the third stage is 3 months to 1 year.

5. The method for oil reservoir exploitation with reduced steam usage according to claim 1, characterized in that: In the third phase, downhole inflow control devices were installed on the horizontal wells.

6. The method for oil reservoir production with reduced steam usage according to claim 5, characterized in that: The downhole inflow control device is an oil pipe type downhole inflow control device.

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