ASYNCHRONOUS CYCLE-BASED OIL EXTRACTION APPARATUS, METHOD AND SYSTEM

Description

TECHNICAL FIELD

The present invention relates to the technical field of oil/gas field exploration, and specifically to an asynchronous cycle-based oil extraction apparatus, method and system.

TECHNICAL BACKGROUND

Unconventional oil reservoirs, such as shale oil and tight oil reservoirs, have abundant resources, which unveil a new field in strategic replacement for petroleum development in the future. Due to poor physical properties including a matrix permeability ≤1 mD (i.e., overburden permeability ≤0.1 mD), these unconventional oil reservoirs have been commonly adopted with depletion development after multi-stage fracturing of horizontal wells at present, which, however, has low and declining recovery rate. After large-scale fracturing, there are multi-scale fractures including natural bedding fractures and artificial fractures. During water injection development, areas with fractures suffer from serious water channeling, so that it is difficult for injected water to enter tight matrix to produce crude oil. Therefore, there is an urgent need for efficient development technologies that can significantly improve the recovery efficiency. Moreover, with regard to complex reservoirs, such as low-permeability reservoirs, fault block reservoirs, heavy oil reservoirs, carbonate rock reservoirs or the like, there is also an urgent need for key technologies to significantly improve the recovery efficiency.

Gas injection development is an important technology for enhancing recovery efficiency in oil fields mainly by injecting gas into the formation for oil displacement, wherein the gas mainly includes hydrocarbon gas and non-hydrocarbon gas. Hydrocarbon gas mainly includes liquefied petroleum gas, rich gas, dry gas (methane), etc., while non-hydrocarbon gas mainly includes CO₂, N₂, air, flue gas, etc.

In terms of oil displacement mechanism, gas molecules are smaller and thus can enter the pores of reservoir rocks more easily compared with water injection, making it easier to establish an effective displacement system to displace crude oil. Meanwhile, gas injection can realize miscibility with crude oil, reduce multiple-phase interfacial tension, expand crude oil and reduce the viscosity of crude oil remarkably, presenting an oil displacement mechanism quite distinct from that of water injection. In terms of injection mode, dry gas huff and puff, continuous gas displacement, and water-gas alternate injection are main gas injection development modes at present.

However, gas injection development is prone to gas channeling in the formation due to gas fluidity, aggravated by the fractures of the oil reservoir and the heterogeneity thereof. In this case, the effect of gas injection development is significantly reduced, which limits the wider application thereof in different types of oil reservoirs. In particular, for unconventional and low-permeability oil reservoirs such as shale oil and tight oil reservoirs, the fractures formed by large-scale fracturing result in severe gas channeling. Thus, an innovative gas injection mode is urgently needed to address these problems.

SUMMARY OF THE INVENTION

The present invention aims to propose an asynchronous cycle-based oil extraction apparatus, method and system, with which the oil extraction efficiency of heterogeneous oil reservoirs with fractures or high-permeability strips can be improved.

In view of the above technical problems, the present invention proposes an asynchronous cycle-based oil extraction apparatus, comprising at least one well group and a control unit, each well group including a wellbore vertical to the ground, and at least one horizontal well group each at least including a first well and a second well, wherein the first well and the second well of each well group share one said wellbore, and both the first well and the second well are horizontal wells parallel to the ground; a casing, a tubing and a packer are arranged within the wellbore, wherein the casing is configured to inject gas into the first well, the tubing is configured to produce crude oil in the second well, and the packer is configured to isolate an annular space between the tubing and the casing; and the control unit is configured to perform: Step 1, injecting gas into the first well through the casing, and soaking the second well; Step 2, continuing to inject the gas into the first well to displace crude oil to the second well, and meanwhile, producing oil by the second well through the tubing; Step 3, soaking the first well and the second well to allow the gas to enter a low-permeability area; and Step 4, continuing to soak the first well and producing oil by the second well through the tubing.

Preferably, the control unit is further configured to obtain environmental parameters of said well group in real time, in order to control oil extraction parameters.

Preferably, the control unit is further configured to determine a minimum miscible pressure of formation fluid and a formation pressure according to the environmental parameters, based on which the oil extraction parameters are controlled.

Preferably, the environmental parameters at least include bottom-hole pressure and wellbore pressure of the first well, and those of the second well, and the oil extraction parameters at least include injection pressure, injection rate and duration of gas, soaking duration, production duration and production rate.

Preferably, the control unit is further configured to: perform Step 2 when the formation pressure is higher than a preset first target pressure in Step 1; perform Step 3 when the formation pressure is lower than a preset second target pressure in Step 2; and perform Step 4 when a derivative of an average formation pressure is zero in Step 3.

Preferably, the first target pressure is 1.4 times the minimum miscible pressure, and the second target pressure is 1.2 times the minimum miscible pressure.

Preferably, the control unit is further configured to increase the injection rate and/or the production rate when both the minimum miscible pressure of the formation fluid and the formation pressure are detected to be less than the target pressure, and reduce the injection rate and/or the production rate when both the minimum miscible pressure of the formation fluid and the formation pressure are detected to be larger than the target pressure.

Preferably, the control unit is further configured to repeatedly perform Steps 1 to 4 in sequence, while obtaining a gas-oil ratio of the crude oil in real time until it is lower than a preset threshold, thus completing asynchronous cycle-based oil extraction.

Preferably, the control unit includes: a sensor, for collecting the environmental parameters of the well group in real time; a calculator, for calculating the formation pressure, the minimum miscible pressure of the formation fluid, and the derivative of the average formation pressure based on the environmental parameters; and a controller for controlling the oil extraction parameters and carrying out an oil extraction mode consisting of Steps 1 to 4.

Preferably, each well group includes a plurality of said horizontal well groups, with an angle formed between two adjacent horizontal well groups ranging from 90° to 180°.

Preferably, the first well and the second well of a same horizontal well group are parallel to each other along a vertical direction of the wellbore, with a distance therebetween twice a half height of a single well fracture.

Preferably, the gas is hydrocarbon gas and/or non-hydrocarbon gas, wherein the hydrocarbon gas is at least one of liquefied petroleum gas, rich gas and dry gas, while the non-hydrocarbon gas is at least one of CO₂, N₂, air and flue gas.

Preferably, the gas is added with chemical agent for inhibiting gas channeling, which is foam or gel.

Preferably, an oil production area to be developed is an unconventional reservoir or a conventional reservoir, wherein the unconventional reservoir is selected from shale oil and tight oil reservoirs, and the conventional reservoir is selected from at least one of low-permeability reservoir, fault block reservoir, heavy oil reservoir and carbonate rock reservoir.

Preferably, the first wells of a plurality of horizontal well groups and/or the second wells thereof work asynchronously.

According to another aspect of the present invention, an asynchronous cycle-based oil extraction method performed by means of said oil extraction apparatus is proposed, comprising: Step S1, providing at least one well group in the oil production area to be developed, each well group including the wellbore vertical to the ground, and at least one horizontal well group each at least including the first well and the second well which are horizontal wells parallel to the ground, wherein the first well and the second well of each well group share one said wellbore, and the casing for injecting gas into the first well, the tubing for producing crude oil in the second well, and the packer for isolating the annular space between the tubing and the casing are arranged within the wellbore; Step S2, injecting gas into the first well through the casing, and soaking the second well; Step S3, continuing to inject the gas into the first well to displace crude oil to the second well, and meanwhile, producing oil by the second well through the tubing; Step S4, soaking the first well and the second well to allow the gas to enter the low-permeability area; and Step S5, continuing to soak the first well, and producing oil by the second well through the tubing.

Preferably, the method further comprises repeatedly performing Steps S2 to S5 in sequence, while obtaining the gas-oil ratio of the crude oil in real time until it is lower than the preset threshold, thus completing the asynchronous cycle-based oil extraction.

Preferably, each well group includes the plurality of said horizontal well groups, with the angle formed between two adjacent horizontal well groups ranging from 90° to 180°.

Preferably, the first well and the second well of a same horizontal well group are parallel to each other along the vertical direction of the wellbore, with the distance therebetween twice the half height of the single well fracture.

Preferably, the gas is hydrocarbon gas and/or non-hydrocarbon gas, wherein the hydrocarbon gas is at least one of liquefied petroleum gas, rich gas and dry gas, while the non-hydrocarbon gas is at least one of CO₂, N₂, air and flue gas.

Preferably, the gas is added with chemical agent for inhibiting gas channeling, which is foam or gel.

Preferably, the oil production area to be developed is an unconventional reservoir or a conventional reservoir, wherein the unconventional reservoir is selected from shale oil and tight oil reservoirs, and the conventional reservoir is selected from at least one of low-permeability reservoir, fault block reservoir, heavy oil reservoir and carbonate rock reservoir.

Preferably, the first wells of the plurality of horizontal well groups and/or the second wells thereof work asynchronously.

The present invention further proposes an asynchronous cycle-based oil extraction system, comprising said asynchronous cycle-based oil extraction apparatus, and a gas recovery device for separation and recovery of gas flowing out of the well group.

Compared with the prior arts, one or more of the embodiments in the above technical solutions have the following advantages or advantageous effects.

The control unit is configured to perform the following operations. In Step 1, gas is injected into the first well through the casing, while the second well is soaked. In Step 2, gas continues to be injected into the first well to displace crude oil to the second well, while the second well produces oil through the tubing. In Step 3, the first well and the second well are soaked to allow the gas to enter a low-permeability area. In Step 4, the first well continues to be soaked, while the second well produces oil through the tubing.

In the procedure from Step 1 to Step 4, gas is injected into the first well only in Step 1 and Step 2. That is, between other adjacent steps, for example, between Step 2 and Step 3, no gas is injected into the first well. Based on mechanisms of pressure increase and miscibility for production of crude oil, displacement of crude oil, diffusion during soaking, expansion for production of crude oil, and depressurization and displacement of crude oil through dissolved gas, the oil extraction apparatus, method and system according to the present invention can overcome the bottleneck problems of injecting CO₂ to develop unconventional reservoirs such as shale oil and tight oil reservoirs, and achieving efficient gas injection development of heterogeneous reservoirs with fractures or high-permeability strips.

In the four steps of a single cycle, gas is injected to the injection well only in the first step and the second step, while gas injection is not required in other two steps. In this manner, better oil extraction effect can be achieved with less gas injection, effectively improving the gas-oil ratio and cost effectiveness. Moreover, the low-cost three-dimensional injection and extraction mode according to the present invention proposes two horizontal wells arranged in the vertical direction and sharing the vertical section of the wellbore, thus effectively reducing the drilling cost per well. With the casing for gas injection and the tubing for oil production, the integrated injection and extraction through two horizontal wells can be realized, thus further improving the efficiency of oil extraction.

Other features and advantages of the present invention will be set forth in the description which follows, and, in part, will be apparent from the description, or may be learned from the implementation of the present invention. The objective and other advantages of the present invention may be realized and attained from the structure particularly pointed out in the description, claims and drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings are used to provide a further understanding on the present invention, and constitute a part of the description. Together with the embodiments of the present invention, the drawings are intended to explain the present invention, but not constitute any limitation to the present invention. In the drawings:

FIG. 1 schematically shows an asynchronous cycle-based oil extraction apparatus in use according to embodiments of the present application;

FIG. 2 is a top view schematically showing a first embodiment of the asynchronous cycle-based oil extraction apparatus according to the present application;

FIG. 3 is a top view schematically showing a second embodiment of the asynchronous cycle-based oil extraction apparatus according to the present application;

FIG. 4 is a flow diagram schematically showing an asynchronous cycle-based oil extraction method according to embodiments of the present application; and

FIG. 5 schematically shows cycle recovery efficiency in the asynchronous cycle-based oil extraction method according to embodiments of the present application.

DETAILED DESCRIPTION OF EMBODIMENTS

The implementation mode of the present invention will be explained in detail with reference to the embodiments and the accompanying drawings, whereby it can be fully understood how to solve the technical problem by the technical means according to the present invention, implement the technical solution, and achieve the technical effects thereof. It should be noted that all the embodiments and the technical features defined therein may be combined together if there is no conflict, and the technical solutions obtained in this manner shall all fall within the scope of protection of the present invention.

In addition, the steps illustrated in the flow chart in the drawings can be performed in a computer system containing a set of computer-executable instructions. Moreover, although a logical sequence is shown in the flow chart, in some cases these steps as shown or described may be performed in an order different than that shown herein.

Unconventional oil reservoirs, such as shale oil and tight oil reservoirs, have abundant resources, which unveil a new field in strategic replacement for petroleum development in the future. Due to poor physical properties including a matrix permeability ≤1 mD (i.e., overburden permeability ≤0.1 mD), these unconventional oil reservoirs have been commonly adopted with depletion development after multi-stage fracturing of horizontal wells at present, which, however, has low and declining recovery rate. After large-scale fracturing, there are multi-scale fractures including natural bedding fractures and artificial fractures. During water injection development, areas with fractures suffer from serious water channeling, so that it is difficult for injected water to enter tight matrix to produce crude oil. Therefore, there is an urgent need for efficient development technologies that can significantly improve the recovery efficiency. Moreover, with regard to complex reservoirs, such as low-permeability reservoirs, fault block reservoirs, heavy oil reservoirs, carbonate rock reservoirs or the like, there is also an urgent need for key technologies to significantly improve the recovery efficiency.

Gas injection development is an important technology for enhancing recovery efficiency in oil fields mainly by injecting gas into the formation for oil displacement, wherein the gas mainly includes hydrocarbon gas and non-hydrocarbon gas. Hydrocarbon gas mainly includes liquefied petroleum gas, rich gas, dry gas (methane), etc., while non-hydrocarbon gas mainly includes CO₂, N₂, air, flue gas, etc.

In terms of oil displacement mechanism, gas molecules are smaller and thus can enter the pores of reservoir rocks more easily compared with water injection, making it easier to establish an effective displacement system to displace crude oil. Meanwhile, gas injection can realize miscibility with crude oil, reduce multiple-phase interfacial tension, expand crude oil and reduce the viscosity of crude oil remarkably, presenting an oil displacement mechanism quite distinct from that of water injection. In terms of injection mode, dry gas huff and puff, continuous gas displacement, and water-gas alternate injection are main gas injection development modes at present.

However, gas injection development is prone to gas channeling in the formation due to gas fluidity, aggravated by the fractures of the oil reservoir and the heterogeneity thereof. In this case, the effect of gas injection development is significantly reduced, which limits the wider application thereof in different types of oil reservoirs. In particular, for unconventional and low-permeability oil reservoirs such as shale oil and tight oil reservoirs, the fractures formed by large-scale fracturing result in severe gas channeling. Thus, an innovative gas injection mode is urgently needed to address these problems.

The present invention proposes an asynchronous cycle-based oil extraction apparatus. The oil extraction apparatus comprises at least one well group and a control unit. Each well group includes a wellbore and at least one horizontal well group, each horizontal well group at least including a first well and a second well. Each well group shares one said wellbore vertical to the ground. Both the first well and the second well are horizontal wells parallel to the ground. A casing, a tubing and packers are arranged within the wellbore. The casing is configured to inject gas into the first well, the tubing is configured to produce crude oil in the second well, and the packers are configured to isolate an annular space between the tubing and the casing of the wellbore, in order to ensure that the gas injected from the casing enters a horizontal section of the first well. The control unit is configured to perform the following operations. In Step 1, gas is injected into the first well through the casing, while the second well is soaked. In Step 2, gas continues to be injected into the first well to displace crude oil to the second well, while the second well produces oil through the tubing. In Step 3, the first well and the second well are soaked to allow the gas to enter a low-permeability area. In Step 4, the first well continues to be soaked, while the second well produces oil through the tubing. In the procedure from Step 1 to Step 4, gas is injected into the first well only in Step 1 and Step 2. That is, between other adjacent steps, for example, between Step 2 and Step 3, no gas is injected into the first well.

Optionally, the control unit is further configured to repeatedly perform Step 2 to Step 4 in sequence, while obtaining a gas-oil ratio of the crude oil in real time. When the gas-oil ratio is lower than a preset threshold, the asynchronous-cycle oil extraction is completed.

According to the present invention, two horizontal wells, i.e., the first well and the second well, are arranged in a vertical direction and share a vertical section of the wellbore, thus effectively reducing the drilling cost per well. Horizontal sections of the two wells are parallel to each other for staged fracturing. A vertical distance between the two horizontal wells is twice a half height of single well fracture, in order to control more reserves and maximize the Estimated Ultimate Recovery (EUR) of single well.

In Step 1, gas is injected into the first well through the casing, while the second well is soaked. The injected gas may be hydrocarbon gas and/or non-hydrocarbon gas, wherein hydrocarbon gas may be liquefied petroleum gas, rich gas, dry gas, etc., while non-hydrocarbon gas may be CO₂, N₂, air, flue gas, etc. The specific positions of the first well and the second well and the communication therebetween depend on specific formation conditions of the oil extraction area. In Step 1, the second well is soaked mainly to prevent the injected gas from being escaped from the second well, so that the injected gas remains in the reservoir to increase the pressure thereof. At this time, the gas continues to diffuse into the pores of the reservoir. Step 1 can increase the pressure of the entire formation, thus realizing the miscibility of the injected gas and crude oil of the formation, while reducing stress susceptibility of the reservoir and improving seepage capacity and oil displacement efficiency. According to different pressure-bearing abilities, the casing can be made of steel of different grades.

In Step 2, gas continues to be injected into the first well, in order to displace crude oil to the second well, while the second well produces oil through the tubing. According to a preferred embodiment, the production of the second well includes extracting, outputting and collecting the crude oil in the second well, wherein the oil extraction operation is performed at the same time as the gas injection operation of the first well. Step 2 can realize effective displacement between wells through gas and displace crude oil in fractures or high-permeability channels efficiently, in order to quickly extract the crude oil in the flowable area. Meanwhile, a contact area between the injected gas and the matrix or low-permeability area can be increased, thereby effectively improving the production rate of crude oil in the matrix or low-permeability area. According to different pressure-bearing abilities, the casing can be made of steel of different grades.

In Step 3, the first well and the second well are both soaked to allow the gas to enter the low-permeability area. Step 3 is performed mainly through the diffusion of gas during the soaking procedure, wherein the gas can enter the crude oil through diffusion, in order to expand the crude oil and reduce the multi-phase interfacial tension as well as the viscosity of the crude oil. The soaking procedure in Step 3 can weaken the channeling effect of the gas, so that the gas can enter the matrix or low-permeability area through diffusion, thereby expanding the crude oil, reducing the interfacial tension and the viscosity of the crude oil. Hence, the crude oil in the matrix and low-permeability area can be efficiently produced.

In Step 4, the first well continues to be soaked, while the second well produces oil through the tubing. The first well continues to be soaked because no gas will be injected into and released from the first well when the first well is in a shut-in state, so that a part of the gas near the first well continues to diffuse into the pores of the reservoir, while the other part flows to the second well for displacement. Therefore, Step 4 is performed to displace the remaining crude oil to the second well through the gas. Through the depressurization and depletion development of the production well, dissolved gas displacement can be fully exerted to achieve the efficient extraction of the remaining oil in the matrix, low-permeability area and between wells. At the same time, no gas injection is required in this step, which can save injection costs, increase gas-oil ratio and improve cost effectiveness.

In the procedure from Step 1 to Step 4, gas is injected into the first well only in Step 1 and Step 2.

In the above steps, when a formation pressure in Step 1 is higher than a preset first target pressure, Step 2 is carried out; when a formation pressure in Step 2 is lower than a preset second target pressure, Step 3 is carried out; and when a derivative of an average formation pressure in Step 3 is zero, Step 4 is carried out. The first target pressure is 1.4 times a minimum miscible pressure, and the second target pressure is 1.2 times the minimum miscible pressure.

One oil extraction cycle consists of Step 1 to Step 4 carried out once in sequence. When multiple oil extraction cycles are carried out, injection wells and production wells of adjacent oil extraction cycles can be interchanged. For example, in a first oil extraction cycle, the first well is the injection well and the second well is the production well, while in a second oil extraction cycle, the first well may be the production well and the second well may be the injection well.

In the entire oil extraction and development procedure, the injection wells of all well groups may be synchronous with each other while the production wells of all well groups may be synchronous with each other. Also, several well groups can be combined to form a large well group, the wells in which may be synchronous with each other. Alternatively, the asynchronous cycle-based injection and extraction can be performed on the well groups in positive or reverse sequence, or in irregular order. Preferably, the first wells of a plurality of horizontal well groups and/or the second wells thereof work based on the asynchronous cycle.

In the asynchronous cycle-based injection and extraction, a chemical agent for inhibiting gas channeling can be added during the injection of the injection well according to actual conditions in the production well. The chemical agent may be foam system, gel system, or other systems that can effectively inhibit gas channeling. The injection of the injection well in a single cycle can also adopt modes such as alternate injection of gas and water or the like, in order to effectively inhibit gas channeling.

Further, the oil production area to be developed may be an unconventional reservoir or a conventional reservoir, wherein the unconventional reservoir is selected from shale oil and tight oil reservoirs, and the conventional reservoir is selected from at least one of low-permeability reservoir, fault block reservoir, heavy oil reservoir and carbonate rock reservoir.

For each step of a single cycle, key parameters such as gas injection pressure, injection rate, injection time, soaking time, production time and production rate can be optimized by laboratory physical simulation or numerical simulation.

In the four steps of the single cycle, gas is injected to the injection well only in the first step and the second step, while gas injection is not required in other two steps. Thus, better oil extraction effect can be achieved with less gas injection, effectively improving the gas-oil ratio and cost effectiveness.

The control unit is further configured to obtain environmental parameters of said well group in real time, in order to control oil extraction parameters. Specifically, the minimum miscible pressure of the formation fluid and the formation pressure are determined according to the environmental parameters, based on which the oil extraction parameters are controlled. For example, when the average formation pressure is lower than the minimum miscible pressure, an injection volume is controlled in real time with a target pressure of 1.4 MMP, and the injection rate is no more than 90% of a maximum injection rate of an injection pump. When the average formation pressure is higher than 1.4 MMP, the first step is skipped to directly move on to the second step.

The environmental parameters at least include bottom-hole pressure and wellbore pressure of the first well, and those of the second well. The oil extraction parameters at least include injection pressure, injection rate and duration of gas, soaking duration, production duration and production rate. The first well and the second well of the same horizontal well group are arranged in parallel along the vertical direction of the wellbore, with a distance therebetween twice the half height of single well fracture.

According to a particular embodiment, as shown in FIG. 1, two horizontal wells are arranged along the vertical direction, namely an injection well m and a production well n, which share the vertical section of the wellbore. The two horizontal wells can initially adopt the depletion development mode, or directly enter an asynchronous cycle-based injection and extraction stage. When the depletion development mode is adopted, the first well produces oil from the annular space between a tubing j and a casing i, and the second well produces oil from the tubing j.

In the asynchronous cycle-based injection and extraction, the first well functions as the injection well m, and the second well functions as the production well n. In the vertical section of the wellbore, packers k seal the annular space between the tubing and the casing. At the beginning of injection, CO₂ is injected from an injection end c of a wellhead tree into the annular space between the tubing and the casing, thus entering a horizontal section of the injection well m. When the production well n produces oil, the produced fluid flows into the tubing of the production well n, and then extracted from a production nozzel b of the wellhead tree.

Specifically, in the procedure of asynchronous cycle-based CO₂ injection and extraction, automatic control is performed through the control unit a arranged at the wellhead tree for intelligent injection and extraction. The control unit a includes a sensor, a calculator and a controller, wherein the sensor is configured to collect the environmental information of the well group in real time, the calculator is configured to calculate the formation pressure, the minimum miscible pressure of the formation fluid, and the derivative of the average formation pressure based on the collected environmental parameters, and the controller is configured to control the oil extraction parameters, for performing the oil extraction mode consisting of the above Steps 1 to 4. Further, the sensor is configured to collect real-time data of a second pressure gauge f of the casing at the wellhead, a first pressure gauge d, a tubing gas composition analysis system e, a third pressure gauge g of the injection well m, and a fourth pressure gauge h of the production well n. The calculator is configured to collect real-time data of a bottom-hole pressure gauge and calculate the average formation pressure in real time through a built-in mathematical model. The collected tubing gas composition is subtracted from the original formation fluid composition to obtain the current formation fluid composition, based on which a corresponding molecular weight is calculated. Further, the minimum miscible pressure (MMP) of the formation fluid is calculated in real time with a data model as follows:

MMP ⁢ = [ ( 7 . 7 ⁢ 27 × MW × 1 . 0 ⁢ 0 ⁢ 5 T ) - 4 . 3 ⁢ 77 × MW - 3 ⁢ 29 ] / 145 ,

• • wherein MW denotes the molecular weight, and T denotes a reservoir temperature. Moreover, the calculator is further configured to calculate the derivative of the average formation pressure in real time.

In addition, the controller is further configured to, based on the calculated real-time minimum miscible pressure (MMP) of the formation fluid in combination with the target pressure, calculate and optimize the injection rate and production rate through the built-in model. For example, the injection rate and/or the production rate is increased when both the minimum miscible pressure of the formation fluid and the formation pressure are less than the target pressure, and reduced when both the minimum miscible pressure of the formation fluid and the formation pressure are larger than the target pressure.

Further, the controller is configured to control, in accordance with the requirements of the asynchronous cycle-based injection and extraction, the injection pump, as well as the injection end c and the production nozzle b of the wellhead tree in real time, for intelligent regulation of injection and extraction, thereby achieving efficient reservoir development.

Preferably, each well group may include a plurality of said horizontal well groups, with an angle formed between two adjacent horizontal well groups ranging from 90° to 180°. FIG. 2 is a top view schematically showing a first embodiment of the asynchronous cycle-based oil extraction apparatus according to the present application. FIG. 3 is a top view schematically showing a second embodiment of the asynchronous cycle-based oil extraction apparatus according to the present application. The well group of the oil extraction apparatus is shown in FIG. 2 as a top view, which comprises a first wellbore 300, a first horizontal well group 301, a second horizontal well group 302, a third horizontal well group 303 and a fourth horizontal well group 304. Each horizontal well group only comprises a first well and a second well, with an angle formed between two adjacent horizontal well groups of 90°. As shown in FIG. 3, the well group comprises a second wellbore 400, a fifth horizontal well group 401 and a sixth horizontal well group 402, with an angle formed between two adjacent horizontal well groups of 180°.

The asynchronous cycle-based oil extraction apparatus according to the present invention can achieve efficient, automatic and intelligent control, and provide a low-cost three-dimensional injection and extraction mode for the asynchronous cycle-based gas injection and oil extraction method.

The oil extraction apparatus can realize an oil displacement efficiency exceeding 90% based on mechanisms of pressure increase and miscibility for production of crude oil, displacement of crude oil, diffusion during soaking, expansion for production of crude oil, and depressurization and displacement of crude oil through dissolved gas, thus overcoming the bottleneck problems of injecting CO₂ to develop unconventional reservoirs such as shale oil and tight oil reservoirs, and achieving efficient gas injection development of heterogeneous reservoirs with fractures or high-permeability strips. In the four steps of a single cycle, gas is injected to the injection well only in the first step and the second step, while gas injection is not required in other two steps. In this manner, better oil extraction effect can be achieved with less gas injection, effectively improving the gas-oil ratio and cost effectiveness. Moreover, the low-cost three-dimensional injection and extraction mode according to the present invention proposes two horizontal wells arranged in the vertical direction and sharing the vertical section of the wellbore, thus effectively reducing the drilling cost per well. With the casing for gas injection and the tubing for oil production, the integrated injection and extraction through two horizontal wells can be realized, thus further improving the efficiency of oil extraction. According to the present invention, the sensor, the calculator and the controller are integrated on the wellhead tree through intelligent control, thereby realizing real-time calculation and precise control of the average formation pressure, the minimum miscible pressure of the formation fluid, the target formation pressure, the injection rate and the production rate.

Based on said asynchronous cycle-based oil extraction apparatus, the present invention further proposes an asynchronous cycle-based oil extraction method, which is performed by means of said asynchronous cycle-based oil extraction apparatus, and mainly applicable to the development of unconventional resources such as shale oil and tight oil reservoirs, and other special lithologic reservoirs including low-permeability reservoir, heavy oil reservoir, integral reservoir, fault block reservoir, high water cut reservoir, high-temperature and high-salinity reservoir, carbonate rock reservoir, etc.

FIG. 4 is a flow diagram showing steps of the asynchronous cycle-based oil extraction method according to the embodiments of the present application. As shown in FIG. 4, Step S101 includes providing at least one well group in an area to be developed, each well group including a wellbore and at least one horizontal well group, each horizontal well group at least including a first well and a second well which are horizontal wells parallel to the ground, wherein the wells of each well group share one said wellbore vertical to the ground. The first well may function as the injection well and the second well may function as the production well. Each well group may include a plurality of the first wells and a plurality of second wells. The first well and the second well may adopt different injection and extraction modes, and work based on asynchronous cycles. The first well and the second well of a same horizontal well group are parallel to each other along the vertical direction of the wellbore, with a distance therebetween twice the half height of single well fracture. Each well group may include a plurality of said horizontal well groups. Preferably, an angle formed between two adjacent horizontal well groups is 180°.

A casing, a tubing and packers are arranged within the wellbore. The casing is configured to inject gas into the first well, the tubing is configured to produce crude oil in the second well, and the packers are configured to isolate the tubing and the casing.

According to the present invention, two horizontal wells, i.e., the first well and the second well, are arranged in the vertical direction and share the vertical section of the wellbore, thus effectively reducing the drilling cost per well. Horizontal sections of the two wells are parallel to each other for staged fracturing. A vertical distance between the two horizontal wells is twice a half height of single well fracture, in order to control more reserves and maximize the Estimated Ultimate Recovery (EUR) of single well.

Step S102 includes injecting gas into the first well through the casing and soaking the second well. The injected gas may be hydrocarbon gas and/or non-hydrocarbon gas, wherein hydrocarbon gas may be liquefied petroleum gas, rich gas, dry gas, etc., while non-hydrocarbon gas may be CO₂, N₂, air, flue gas, etc. The specific positions of the first well and the second well and the communication therebetween depend on specific formation conditions of the oil extraction area.

Step S102 can increase the pressure of the entire formation, thus realizing the miscibility of the injected gas and crude oil of the formation, while reducing stress susceptibility of the reservoir and improving seepage capacity and oil displacement efficiency.

Step S103 includes continuing to inject gas into the first well to displace crude oil to the second well, and meanwhile producing oil by the second well through the tubing. In a preferred embodiment, the production of the second well includes extracting, outputting and collecting the crude oil in the second well.

Step S103 can realize effective displacement between wells through gas and displace crude oil in fractures or high-permeability channels efficiently, in order to quickly extract the crude oil in the flowable area. Meanwhile, a contact area between the injected gas and the matrix or low-permeability area can be increased, thereby effectively improving the production rate of crude oil in the matrix or low-permeability area.

Step S104 includes soaking both the first well and the second well to allow the gas to enter the low-permeability area. Step S104 is performed mainly through the diffusion of gas during the soaking procedure, wherein the gas can enter the crude oil through diffusion, in order to expand the crude oil and reduce the multi-phase interfacial tension as well as the viscosity of the crude oil. The soaking procedure in Step S104 can weaken the channeling effect of the gas, so that the gas can enter the matrix or low-permeability area through diffusion, thereby expanding the crude oil, reducing the interfacial tension and the viscosity of the crude oil. Hence, the crude oil in the matrix and low-permeability area can be efficiently produced.

Step S105 includes continuing to soak the first well while producing oil by the second well through the tubing. Step S105 is performed to displace the remaining crude oil to the second well through the gas. Through the depressurization and depletion development of the production well, dissolved gas displacement can be fully exerted to achieve the efficient extraction of the remaining oil in the matrix, low-permeability area and between wells. At the same time, no gas injection is required in this step, which can save injection costs, increase gas-oil ratio and improve cost effectiveness.

From Step S102 to Step S105, gas is injected into the first well only in Step S102 and Step S103. There is no gas injection into the first well between other adjacent steps, for example, between Step S103 and Step S104.

In the above steps, when a formation pressure in Step S102 is higher than a preset first target pressure, Step S103 is carried out; when the formation pressure in Step S103 is lower than a preset second target pressure, Step S104 is carried out; and when a derivative of the average formation pressure in Step S104 is zero, Step S105 is carried out.

One oil extraction cycle consists of Step S101 to Step S105 carried out once in sequence. When multiple oil extraction cycles are carried out, injection wells and production wells of adjacent oil extraction cycles can be interchanged. For example, in a first oil extraction cycle, the first well is the injection well and the second well is the production well, while in a second oil extraction cycle, the first well may be the production well and the second well may be the injection well.

In the entire oil extraction and development procedure, the injection wells of all well groups may be synchronous with each other while the production wells of all well groups may be synchronous with each other. Also, several well groups can be combined to form a large well group, the wells in which may be synchronous with each other. Alternatively, the asynchronous cycle-based injection and extraction can be performed on the well groups in positive or reverse sequence, or in irregular order. Preferably, the first wells of a plurality of horizontal well groups and/or the second wells thereof work based on the asynchronous cycle.

In the asynchronous cycle-based injection and extraction, a chemical agent for inhibiting gas channeling can be added during the injection of the injection well according to actual conditions in the production well. The chemical agent may be foam system, gel system, or other systems that can effectively inhibit gas channeling. The injection of the injection well in a single cycle can also adopt modes such as alternate injection of gas and water or the like, in order to effectively inhibit gas channeling.

For each step of a single cycle, key parameters such as gas injection pressure, injection rate, injection time, soaking time, production time and production rate can be optimized by laboratory physical simulation or numerical simulation.

In the four steps of the single cycle, gas is injected to the injection well only in the first step and the second step, while gas injection is not required in other two steps. Thus, better oil extraction effect can be achieved with less gas injection, effectively improving the gas-oil ratio and cost effectiveness.

The oil extraction method further comprises obtaining environmental parameters of said well group in real time, in order to control oil extraction parameters. Specifically, the minimum miscible pressure of the formation fluid and the formation pressure are determined according to the environmental parameters, based on which the oil extraction parameters are controlled. For example, when the average formation pressure is lower than the minimum miscible pressure, an injection volume is controlled in real time with a target pressure of 1.4 MMP, and the injection rate is no more than 90% of a maximum injection rate of an injection pump. When the average formation pressure is higher than 1.4 MMP, the first step is skipped to directly move on to the second step. The environmental parameters at least include bottom-hole pressure and wellbore pressure of the first well, and those of the second well. The oil extraction parameters at least include injection pressure, injection rate and duration of gas, soaking duration, production duration and production rate.

Specifically, in the procedure of asynchronous cycle-based CO₂ injection and extraction, automatic control is performed through the control unit a arranged at the wellhead tree for intelligent injection and extraction. The control unit a includes the sensor, the calculator and the controller. The sensor is configured to collect real-time data of the second pressure gauge f of the casing at the wellhead, the first pressure gauge d, the tubing gas composition analysis system e, the third pressure gauge g of the injection well m, and the fourth pressure gauge h of the production well n. The calculator is configured to collect real-time data of the bottom-hole pressure gauge and calculate the average formation pressure in real time through the built-in mathematical model. The collected tubing gas composition is subtracted from the original formation fluid composition to obtain the current formation fluid composition, based on which the corresponding molecular weight is calculated. Further, the minimum miscible pressure (MMP) of the formation fluid is calculated in real time with the data model as follows:

MMP ⁢ = [ ( 7 . 7 ⁢ 2 ⁢ 7 × MW × 1. 0 ⁢ 0 ⁢ 5 T ) - 4 . 3 ⁢ 7 ⁢ 7 × MW - 329 ] / 145 ,

• • wherein MW denotes the molecular weight, and T denotes the reservoir temperature. According to the target pressure, the injection rate and production rate are calculated and optimized through the built-in model. Moreover, the calculator is further configured to calculate the derivative of the average formation pressure in real time. Further, the controller is configured to control, in accordance with the requirements of the asynchronous cycle-based injection and extraction, the injection pump, as well as the injection end c and the production nozzle b of the wellhead tree in real time, for intelligent regulation of injection and extraction, thereby achieving efficient reservoir development.

For example, in Step A, the sensor of the control unit a arranged at the wellhead tree for intelligent injection and extraction collects the data of the bottom-hole pressure gauges of two horizontal wells. An average of bottom-hole pressures of the two horizontal wells is then calculated by the calculator in real time, in order to obtain the average formation pressure. A target average formation pressure is 1.4 times the minimum miscible pressure (MMP). The injection rate is calculated and optimized, followed by the injection of CO₂. When the average formation pressure reaches 1.4 times the minimum miscible pressure (MMP), the control unit a turns on the production nozzle b to enter Step B. Step A is performed mainly for increasing pressure and realizing miscibility.

In Step B, the average formation pressure which is 1.2 times the minimum miscible pressure (MMP) is taken as the target average formation pressure, for performing intelligent injection, displacement and extraction. CO₂ is injected into the injection well, while the production well produces oil. An injection-extraction ratio is set by the calculator of the control unit a. Based on a fixed liquid volume at the production nozzle, the production well produces oil at the production rate calculated by the control unit a. In the entire displacement procedure, the average formation pressure gradually decreases. The calculator of the control unit a calculates the average formation pressure in real time. When the average formation pressure drops to 1.2 times the minimum miscible pressure (MMP), both the injection well and the production well are shut in to move on to the next step. Step B is performed mainly for displacing crude oil through differential pressure and gravity, in order to expand a swept area of CO₂ in the reservoir.

In Step C, both the horizontal wells are simultaneously shut in for soaking. The control unit a determines in real time whether the derivative of the average formation pressure is zero. When the derivative reaches zero, the soaking ends to move on to the next step. Step C is performed mainly for diffusing CO₂ to enter the matrix during the soaking and driving crude oil in the fractures to the production well under gravity for the production of crude oil.

In Step D, the injection well remains shut-in, while the production well produces oil. The control unit a calculates the average formation pressure in real time. When the average formation pressure drops to 80 percent of the minimum miscible pressure (MMP), the production well is shut in. Thus, the four steps of the first cycle are completed, and then the next cycle starts. Step D is performed mainly for displacing crude oil through dissolved gas and gravity.

The four steps of the above cycle are repeated, while the gas-oil ratio of the crude oil is obtained in real time until it is lower than a preset threshold, thus completing the oil extraction. The production continues if the output is higher than an economic limit output, but ends if not.

A separation and recovery device for produced CO₂ can be arranged at the wellhead, for separating CO₂ from the produced fluid of the production well and re-injecting it to the injection well, thereby realizing separation and re-injection on the same drilling pad. In this manner, CO₂ can be recycled to reduce the cost thereof.

Embodiment 1

A target shale oil reservoir with a thickness of 90 meters is developed in a two-layered three-dimensional mode. A horizontal section of a first well in a horizontal well group is 15 meters from the bottom hole. The horizontal section of the first well, with a length of 500 meters, is fractured in 10 sections. Microseismic monitoring results show that a half height of the horizontal well fracture is 15 meters. A horizontal section of a second well is 45 meters from the bottom hole. The horizontal section of the second well, with a length of 500 meters, is fractured in 10 sections. Microseismic monitoring results show that a height of the horizontal well fracture is 15 meters. The horizontal sections of the two horizontal wells are parallel to each other and share a vertical section. CO₂ is injected into the upper horizontal well from the casing, and produced fluids including crude oil are produced from the tubing of the lower horizontal well.

The wellhead tree is equipped with an intelligent injection-and-extraction control system, in order to perform development directly in an asynchronous cycle-based injection and extraction mode.

The reservoir has an original pressure of 17 MPa and an original temperature of 80 degrees Celsius. The minimum miscibility pressure of the crude oil in the formation and CO₂ is 20 MPa at the reservoir temperature, measured through experiment.

The asynchronous cycle-based injection and extraction mode include the following steps.

In Step A, a bottom-hole pressure of the two horizontal wells is 17 MPa, collected by the sensor of the intelligent injection-and-extraction control system of the wellhead tree. An initial average formation pressure is 17 MPa, and the target average formation pressure is 28 MPa, which is 1.4 times the minimum miscible pressure (MMP). After calculation and optimization, CO₂ is injected at an injection rate of 60 tons per day. The calculator of the intelligent injection-and-extraction control system calculates the average formation pressure in real time. When the average formation pressure reaches 28 MPa, a signal is transmitted to the production end of the wellhead tree, in which case the production nozzle is turned on to move on to Step B.

In Step B, the average formation pressure of 24 MPa, which is 1.2 times the minimum miscible pressure (MMP), is taken as the target average formation pressure, for performing intelligent injection, displacement and extraction. CO₂ is injected into the injection well at the injection rate of 60 tons per day. The injection-extraction ratio is set as 1.1 by the calculator of the intelligent injection-and-extraction control system. Based on a fixed liquid volume at the production nozzle, the production well produces oil at the production rate of 66 tons per day. In the entire procedure, the average formation pressure gradually decreases. The calculator of the intelligent injection-and-extraction control system calculates the average formation pressure in real time. When the average formation pressure drops to 24 MPa, both the injection well and the production well are shut in to move on to the next step.

In Step C, both the horizontal wells are simultaneously shut in for soaking. The intelligent injection-and-extraction control system determines in real time whether the derivative of the average formation pressure is zero. After 30 days of soaking, the derivative reaches zero, in which case the soaking ends to move on to the next step.

In Step D, the injection well remains shut-in, while the production well produces oil at the production rate of 66 tons per day based on a fixed liquid volume at the production nozzle. The intelligent injection-and-extraction control system calculates the average formation pressure in real time. When the average formation pressure drops to 80 percent of the minimum miscible pressure (MMP), i.e., 16 MPa, the production well is shut in. Thus, the four steps of the first cycle are completed, and then the next cycle starts.

After six cycles, the development procedure is completed, with the gas-oil ratio of 0.05 at this time.

FIG. 5 schematically shows cycle recovery efficiency obtained by the asynchronous cycle-based oil extraction method according to embodiments of the present application. As shown in FIG. 5, the recovery efficiency is as high as 34% after six cycles. It is clearly evident that the recovery efficiency is significantly improved. As the number of cycles increases, the recovery efficiency increases rapidly and then slows down, wherein the recovery efficiency in the first cycle is the largest, which is as high as 15.5%. The asynchronous cycle-based oil extraction method according to the present invention can realize an oil displacement efficiency exceeding 90% based on mechanisms of pressure increase and miscibility for production of crude oil, displacement of crude oil, diffusion during soaking, expansion for production of crude oil, gravity drainage, and depressurization and displacement of crude oil through dissolved gas, thus overcoming the bottleneck problems of injecting CO₂ to develop unconventional reservoirs such as shale oil and tight oil reservoirs, and achieving efficient gas injection development of heterogeneous reservoirs with fractures or high-permeability strips. In the four steps of a single cycle, gas is injected to the injection well only in the first step and the second step, while gas injection is not required in other two steps. In this manner, better oil extraction effect can be achieved with less gas injection, effectively improving the gas-oil ratio and cost effectiveness. Moreover, the low-cost three-dimensional injection and extraction mode according to the present invention proposes two horizontal wells arranged in the vertical direction and sharing the vertical section of the wellbore, thus effectively reducing the drilling cost per well. With the casing for gas injection and the tubing for oil production, the integrated injection and extraction through two horizontal wells can be realized, thus further improving the efficiency of oil extraction. According to the present invention, the sensor, the calculator and the controller are integrated on the wellhead tree through intelligent control, thereby realizing real-time calculation and precise control of the average formation pressure, the minimum miscible pressure of the formation fluid, the target formation pressure, the injection rate and the production rate.

According to another aspect of the present invention, an asynchronous cycle-based oil extraction system is also proposed, which includes said oil extraction apparatus, and a gas recovery device for separation and recovery of gas flowing out of the well group. At the beginning of injection, CO₂ is injected from the injection end c of the wellhead tree into the annular space between the tubing and the casing, thus entering a horizontal section of an injection well. When a production well produces oil, the produced fluid flows into a tubing of the production well, in order to be extracted from the production nozzle b of the wellhead tree.

Therefore, gas injection and oil extraction in the same well can be realized, leading to a low-cost three-dimensional injection and extraction mode.

The foregoing is merely illustrative of preferred embodiments of the present invention, but the scope of protection of the present invention is not limited thereto. Any modifications or substitutions that can be readily conceived by one skilled in the art within the technical scope disclosed herein shall fall within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined according to the scope of protection of the claims.

It should be understood that the embodiments of the present invention are not limited to the specific structures, processing steps or materials disclosed herein, but should extend to equivalent substitutions of these features understood by one ordinarily skilled in the art. It should also be understood that the terminology used herein is for the purpose of describing a particular embodiment only, rather than being construed as restriction.

The phrase “an embodiment” or “embodiments” as mentioned in the description means that the particular features, structures or characteristics described in conjunction with the embodiment or embodiments are included in at least one embodiment of the present invention. Thus, the phrase “an embodiment” or “embodiments” used throughout the description does not necessarily refer to the same embodiment.

Although the embodiments of the present invention are described hereinabove, the disclosure is provided for facilitating to understand the implementing mode of the present invention, but rather restricting the present invention. Without departing from the spirit and scope of the present disclosure, one skilled in the art can make various modifications and improvements in forms and details of the implementing mode. The scope of protection of the present invention shall be determined by the appending claims.