Alternating pressure-drive oil extraction method for low-permeability reservoir

Abstract

The invention relates to a low-permeability reservoir alternate pressure-drive oil extraction method, and belongs to the technical field of low-permeability reservoir exploration and development. The invention provides an oil extraction method for low-permeability reservoir carbon dioxide / water alternate pressure drive injection. Through carbon dioxide / water alternate pressure driving, the formation rapidly reaches the minimum miscible pressure of carbon dioxide and crude oil, micro-cracks are formed in the formation and continuously expanded into complex cracks, the seepage capacity of the reservoir is improved, meanwhile, water and gas alternately form a Jamin effect to control fluidity, water channeling and gas channeling, meanwhile, carbon dioxide is dissolved in water to form an acid corrosion pore channel, and therefore the reservoir seepage capacity is improved. And the reservoir permeability is increased.

Description

Technical Field

[0001] This invention relates to an alternating pressure drive method for oil recovery in low-permeability reservoirs, belonging to the field of exploration and development technology for low-permeability reservoirs. Background Technology

[0002] Low-permeability reservoirs (also known as low-permeability oilfields) refer to oilfields with low reservoir permeability, low abundance, and low single-well productivity. There is no unified, fixed standard or boundary for low-permeability oilfields worldwide; it is a relative concept. Different countries have established their own standards based on different periods of oil resource conditions and techno-economic factors, resulting in a wide range of variations. Luo Zhetan and Wang Yuncheng (1986) defined low-permeability reservoirs as those with a permeability less than 100 × 10⁻⁶ m³ / s. -3 μm 2 The oil layer was classified as a low-permeability oil layer; Yan Hengwen et al. (1993) defined the permeability as (10-100)×10 -3 μm 2 The reservoir is classified as a low-permeability reservoir, (0.1-10)×10 -3 μm 2 The reservoir is a reservoir with a special permeability; Tang Zengxiong (1994) classified the low-permeability oilfield reservoir as having a permeability of (10-100)×10 -3 μm 2 Less than 10×10 -3 μm 2 This is an ultra-low permeability oilfield. Li Daopin et al. (1997) proposed a permeability of (0.1-50)×10⁻⁶. -3 μm 2 The reservoirs in these reservoirs are generally referred to as low-permeability oil layers. Based on actual production characteristics, low-permeability oil fields are further divided into three categories according to the average permeability of the oil layer: The first category is general low-permeability oil fields, with an average permeability of (10.1-50)×10 -3 μm 2 The second category is ultra-low permeability oilfields, with an average reservoir permeability of (1.1-10)×10⁻⁶. -3 μm 2 The third category is ultra-low permeability oilfields, with an average reservoir permeability of (0.1-1)×10⁻⁶. -3 μm 2 However, these oil layers are very dense with high bound water saturation, have virtually no natural production capacity, and generally do not have industrial development value.

[0003] Low-permeability oil and gas fields play a crucial role in my country's oil and gas development. More than half of the newly discovered oil and gas reservoirs in my country are low-permeability fields, and the scale of production capacity construction in these fields accounts for over 70% of the total scale of oil and gas field production capacity construction. Low-permeability oil and gas fields have become the main battleground for oil and gas development. Furthermore, my country's low-permeability oil and gas resources are characterized by abundant oil and gas content, diverse reservoir types, and wide distribution. Low-permeability oil and gas reservoirs account for a very high proportion of the proven reserves, approximately two-thirds of the national reserves, indicating enormous development potential.

[0004] However, achieving economical and effective development of low-permeability oil and gas fields presents many challenges. Because low-permeability oil and gas fields are not structural reservoirs but rather lithologic stratigraphic reservoirs, exploration is significantly more difficult. During exploration, accurately understanding the distribution patterns of low-permeability oil and gas fields, controlling their area, and identifying oil and gas enrichment zones are all topics requiring further research. Furthermore, even after accurately identifying low-permeability reservoirs, the inherent characteristics of low abundance and low pressure, coupled with insufficient natural energy, result in very low natural well production. Therefore, improving single-well production in such oil and gas fields through technological innovation is also a problem that needs to be solved.

[0005] Waterflooding is a common development method for low-permeability reservoirs. Its principle is to increase the pressure in the reservoir by injecting large amounts of water, thereby driving oil towards the wellhead and increasing production. In low-permeability reservoirs, water-flooding involves rapid, high-pressure water injection into oil and water wells to increase formation energy. This pressure increases pore pressure in the rock, creating microfractures near the wellbore. These microfractures gradually coalesce to form the main fracture zone, significantly increasing reservoir permeability. However, water-flooding introduces relatively small microfractures, preventing the formation of complex microfractures. It can only displace crude oil in pores larger than 0.1 μm within the microfractures and is prone to water channeling, reducing oil recovery.

[0006] Carbon dioxide flooding is an important method for improving oil recovery in low-permeability reservoirs. Carbon dioxide can expand the volume of crude oil, reduce its viscosity, extract light hydrocarbon components, improve its mobility ratio, and increase its swept volume. Carbon dioxide miscible flooding can significantly improve oil recovery. Furthermore, carbon dioxide can displace crude oil in tiny pores and throats that water flooding cannot reach, entering pores and throats an order of magnitude smaller than water, thus increasing the swept volume. However, low-permeability reservoirs generally have high minimum miscibility pressures between carbon dioxide and crude oil. Simply injecting carbon dioxide to raise formation pressure to achieve miscibility pressure requires a large injection volume and a long injection cycle. Moreover, gas channeling often occurs during carbon dioxide flooding, leading to poor oil displacement results.

[0007] Water-gas alternating flooding is currently an effective method for controlling gas channeling and can improve the gas-driven oil recovery effect. Currently, conventionally used water-gas alternating flooding reservoirs are mainly applied to medium-to-high permeability reservoirs (greater than 50 × 10⁻⁶ m³ / h). -3 μm 2Taking the CO2-water-gas alternating flooding method in Pucheng Shayi, Zhongyuan Oilfield as an example, with 30 tons of gas injected per day and 40 cubic meters of water injected per day, the CO2 content in the well decreases after water-gas alternation, and the gas intake profile is improved. However, for low-permeability or ultra-low-permeability reservoirs that are difficult to inject water, conventional low-speed water injection is difficult to achieve, and conventional low-speed CO2 injection is too slow to improve reservoir permeability through reservoir stimulation, resulting in a long time to see results. Therefore, developing pressure-driven oil recovery methods for low-permeability reservoirs is an urgent problem to be solved in order to increase oil production and improve recovery rate. Summary of the Invention

[0008] The purpose of this invention is to provide an alternating pressure drive oil recovery method for low-permeability reservoirs, which can effectively improve the recovery rate and achieve rapid results.

[0009] To achieve the above objectives, the technical solution of the alternating pressure drive oil recovery method for low-permeability reservoirs in this invention is as follows:

[0010] A method for oil recovery from low-permeability reservoirs using alternating pressure flooding includes the following steps:

[0011] (1) The total injection volume of the pressure drive is obtained based on the comprehensive compressibility coefficient of the target reservoir, reservoir volume, expected recovery formation pressure, and current formation pressure.

[0012] (2) Based on the physical properties of the target reservoir and the formation fluid properties, a three-dimensional numerical model is constructed. Under the constraints of the total injection volume of the pressure drive and the formation micro-fracture pressure, the correspondence between the injection rate of water or carbon dioxide and the degree of recovery is determined, and the optimal injection rate is selected.

[0013] (3) Use the total injection volume of the pressure drive obtained in step (1) and the optimal injection rate obtained in step (2) to determine the optimal alternating slug injection volume and volume ratio;

[0014] (4) Based on the optimal injection rate obtained in step (2) and the optimal alternating slug injection volume and volume ratio obtained in step (3), water and carbon dioxide are injected alternately by slug pressure drive. After the total injection volume of pressure drive is injected, the injection is stopped and the injection well is closed. When the oil pressure change rate of the target oil well is ≤0.1MPa / d, the oil well production is started.

[0015] The beneficial effects of the above technical solution are as follows: The alternating pressure drive oil recovery method for low-permeability reservoirs of the present invention is a pioneering invention. The present invention first controls the total injection volume and injection pressure of the pressure drive, thereby controlling the water injection rate to induce microfractures in the reservoir. Then, by controlling the total injection volume and injection pressure, it controls the carbon dioxide injection rate, allowing liquid carbon dioxide to be rapidly injected into the formation under high pressure. Under the high temperature and pressure environment of the reservoir, the liquid carbon dioxide becomes supercritical, dissolves in the water, and passes through the water wall, migrating with subsequent high-pressure water to the deep pores of the reservoir fractures. A large amount of carbon dioxide instantly transforms into gaseous carbon dioxide at the fracture tip. Carbon dioxide can penetrate into fractures and pores smaller than water. The phase transition of carbon dioxide to fracture causes an increase in pressure at the fracture tip, leading to the expansion of more microfractures and further extension. Simultaneously, the resulting reaction force again impacts the carbon dioxide gas, which dissolves again in the water and reacts to form an unstable carbonic acid solution. The carbonic acid solution is acidic and can dissolve pores. With subsequent alternating water and gas pressure drive injection, an alternating force of expansion-contraction-expansion is ultimately formed, causing the reservoir to continuously form and expand a large number of new microfractures, thus widening the reservoir seepage channels. At the same time, the alternation of water and gas creates the Jamin effect, which controls the mobility, forms a balanced displacement during the pressure drive process, expands the swept volume, and increases the oil recovery rate.

[0016] As a further improvement, the formula for calculating the total injection volume of the pressure drive is as follows: Q 压驱 =C t V(P 目标 -P 目前 ); where Q 压驱 m is the total injection volume of the pressure drive. 3 C t The overall compressibility factor is expressed in MPa. -1 V represents the reservoir volume, in meters. 3 ;P 目标 To restore formation pressure as expected, MPa; P 目前 The current formation pressure is in MPa.

[0017] As a further improvement, the P 目标 The minimum miscibility pressure of crude oil and carbon dioxide in the target oil well is 1.3 to 1.6 times.

[0018] As a further improvement, the formation microfracture pressure includes the water injection-induced formation microfracture pressure P. w1 Carbon dioxide injection induces formation microfracture pressure P w2 The P w1 The formation fracturing pressure P caused by water injection 破裂1 0.8 to 0.95 times; the P w2 The formation fracturing pressure P caused by carbon dioxide injection 破裂2 0.8 to 0.95 times that.

[0019] As a further improvement, the formula for calculating V is: Where V is the reservoir volume, m 3 N represents geological reserves, m 3 ; Porosity; S oi denoted as the original oil saturation; K represents the high-pressure pore expansion rate.

[0020] As a further improvement, K is 0.5-1%.

[0021] As a further improvement, the formula for calculating the overall compression coefficient is as follows: Among them, C f The rock compressibility coefficient is given in MPa. -1 C o The compressibility coefficient of the oil is expressed in MPa. -1 C W Let be the compressibility coefficient of water, in MPa. -1 S oi Original oil saturation; S wi To bind water saturation; denoted as porosity; K represents the high-pressure expansion rate.

[0022] As a further improvement, the average permeability of the low-permeability reservoir is <10.0 × 10⁻⁶. -3 μm 2 . Attached Figure Description

[0023] Figure 1 This is a schematic diagram of the water / carbon dioxide slug injection in this invention;

[0024] Figure 2 This is a schematic diagram of the micro-fracturing mechanism in the pressure-driven injection process of this invention;

[0025] Figure 3 This is a schematic diagram of crack propagation at the crack tip region in this invention;

[0026] Figure 4 This is a graph showing the relationship between the recovery rate and the water injection rate under different water injection and discharge rates in Embodiment 1 of the present invention;

[0027] Figure 5 This is a graph showing the relationship between the recovery rate and the carbon dioxide injection rate under different injection rates in Example 1 of the present invention.

[0028] Figure 6 This is a graph showing the relationship between different pressure-driven water-gas sluice gates and recovery rates in Example 1 of the present invention;

[0029] Figure 7 This is a graph showing the relationship between different alternating small plug segments and the degree of extraction in Embodiment 1 of the present invention;

[0030] Figure 8 This is a diagram showing the CO2 wave drive and its extent under different formation pressures in Embodiment 1 of the present invention;

[0031] Figure 9 This is a graph showing the relationship between permeability and different axial pressures in Example 1 of the present invention;

[0032] Figure 10 This is the curve showing the relationship between effective stress and specific porosity during the water injection and pressurization stage in Embodiment 1 of the present invention.

[0033] Figure 11 The CO2 displacement efficiency curves under different reservoir pressures in Example 1 of this invention are shown.

[0034] Figure 12 The graphs show the changes in enhanced oil recovery rate over production time in Embodiment 1 and Comparative Example 1 of the present invention. Detailed Implementation

[0035] Carbon dioxide flooding is an important method for improving oil recovery in low-permeability reservoirs. However, low-permeability reservoirs generally have high minimum miscibility pressures between carbon dioxide and crude oil. Simply injecting carbon dioxide to raise formation pressure to achieve miscibility pressure requires a large injection volume and a long injection cycle. Furthermore, due to immature and incomplete technology, gas channeling is prone to occur during carbon dioxide flooding. Water-gas alternating flooding is an effective way to control gas channeling and improve gas-driven oil recovery. However, in low-permeability reservoirs, the injection rate of water-gas alternating flooding is slow, and reservoir stimulation cannot be performed to improve reservoir permeability, resulting in a long recovery period. Therefore, this invention provides an alternating pressure flooding method for oil recovery in low-permeability reservoirs.

[0036] The low-permeability reservoir alternating pressure drive oil recovery method of this invention is essentially a carbon dioxide / water alternating slug pressure drive oil recovery method. A schematic diagram of the formation after water and carbon dioxide slug injection is shown below. Figure 1 As shown in the diagram, alternating carbon dioxide / water pressure flooding rapidly brings the formation to the minimum miscibility pressure between carbon dioxide and crude oil. Under water pressure, microfractures first form in the formation. Subsequent pressure flooding with carbon dioxide injects liquid carbon dioxide at high pressure, which rapidly enters the formation. Under the high temperature and pressure environment of the reservoir, the liquid carbon dioxide becomes supercritical, dissolves in the water, and crosses the water wall, migrating with subsequent high-pressure water to the deep pores of the reservoir fractures. A large amount of carbon dioxide instantly transforms into gaseous carbon dioxide at the fracture tip. Carbon dioxide can penetrate into fractures and pores smaller than water, and the phase transition of carbon dioxide to fractures increases the pressure at the fracture tip, causing the fracture tip to expand and extend further into more microfractures. A schematic diagram of the microfracture mechanism during alternating water / gas pressure flooding is shown below. Figure 2 As shown in the diagram, the crack propagation at the crack tip is illustrated in the figure below. Figure 3 As shown.

[0037] Microfractures form in the formation and continuously expand into complex fractures, improving the reservoir's permeability. At the same time, the alternation of water and gas creates the Jamin effect, controlling mobility and water and gas channeling. Meanwhile, carbon dioxide dissolves in water to form acidic dissolution channels, increasing reservoir permeability.

[0038] The present invention will be further described below with reference to specific embodiments. It should be noted that, without conflict, the various embodiments or technical features described below can be arbitrarily combined to form new embodiments. The equipment and raw materials used are all commercially available or commonly used in the art. Unless otherwise specified, the methods in the following embodiments are conventional methods in the art.

[0039] Unless otherwise specified, the operations described in the following embodiments are conventional operations in the art.

[0040] Unless otherwise specified, the raw materials used in the following embodiments are all conventional commercial products in the art.

[0041] In the embodiments and comparative examples of this invention, two oil wells from a low-permeability reservoir in the same block and development stratum were selected, and water-gas alternating pressure drive and water injection pressure drive field experiments were conducted respectively to provide a detailed description of the method described in this invention. The low-permeability reservoir has a burial depth of 3400m, a reservoir temperature of 110℃, an average porosity of 11%, and an average permeability of 5×10⁻⁶. -3 μm 2 Crude oil density 0.83 g / m³ 3 The crude oil viscosity is 3.29 mPa·s, and the carbon dioxide density under formation conditions is 0.7 g / m³. 3 Ground carbon dioxide density is 1.0 g / m³ 3 Geological reserves 4.88×10 4 m 3 The rock compressibility coefficient is 0.0002 MPa. -1 The oil's compressibility is 0.0017 MPa. -1 The compressibility of water is 0.000475 MPa. -1 The original oil saturation was 0.38, the bound water saturation was 0.62, the original formation pressure was 37 MPa, the current formation pressure is 26 MPa, the hydraulic fracturing pressure is 72.3 MPa, and the CO2 fracturing pressure is 54.2 MPa. These reservoir characteristic data can be obtained using conventional methods. Water injection is difficult in this well group, and the waterdrive recovery rate is 2.3%.

[0042] Example 1: An Alternating Pressure Flooding Method for Oil Recovery in Low-Permeability Reservoirs

[0043] Preliminary investigations revealed that existing water-gas alternating flooding technologies primarily control gas channeling and improve the oil displacement effect. However, the injection rate is slow, and reservoir stimulation cannot be performed to improve reservoir permeability, resulting in a long lead time. This invention, through extensive preliminary research and analysis, discovered that by controlling the injection volume and pressure of water-fueled pressure flooding, microfractures are generated in the reservoir. Then, by controlling the injection volume and pressure of carbon dioxide, high-pressure liquid carbon dioxide is rapidly injected into the formation, creating a more complex fracture network on top of the microfractures. This stimulates the reservoir and rapidly increases its permeability. The specific implementation is as follows:

[0044] 1. Parameter optimization

[0045] The process of establishing a three-dimensional numerical model of the target reservoir's physical properties and formation fluid properties using CMG software is as follows:

[0046] Input the reservoir's basic parameters, such as average porosity, permeability, original oil saturation, original formation pressure, and formation temperature, as well as fluid parameters, such as crude oil density and carbon dioxide density, into the CMG software to generate a three-dimensional numerical model.

[0047] Numerical simulation was conducted at a total pressure-driven water injection volume of 10,000 m³. 3 The variable water injection speed v1 is between 100 and 800 m / s. 3 / day, to obtain the recovery rate under different water injection rates, such as Figure 4 As shown, the water injection speed v1 is between 400 and 500 m / s. 3 / day, the harvesting process is better.

[0048] With a total pressure drive carbon dioxide injection volume of 10,000 m³ 3 The variable carbon dioxide injection velocity v2 is between 100 and 450 m / s. 3 / day, to obtain the recovery rate under different carbon dioxide injection rates, such as Figure 5 As shown, the carbon dioxide injection rate v2 is between 300 and 350 m / s. 3 / days, the harvesting rate is better.

[0049] In the total injection volume of pressure drive (Q) 压驱 10000m 3 The carbon dioxide injection speed v2 is at 350m 3 / day, water injection rate v1 is 500m 3 / day, the volume ratio of the pressure-driven water sluice and the pressure-driven carbon dioxide sluice was used to obtain the recovery rate under different volume ratios of pressure-driven water sluice and pressure-driven carbon dioxide sluice, such as Figure 6 As shown, when the volume ratio of the pressure-driven water sluice block to the pressure-driven carbon dioxide sluice block is 1:1, the recovery rate is better.

[0050] In the total injection volume of pressure drive (Q)压驱 10000m 3 The carbon dioxide injection speed v2 is at 350m 3 / day, water injection rate v1 is 500m 3 / day, total surface pressure-driven water injection volume 5000m³ 3 The total injection volume of liquid carbon dioxide via ground-based pressure-driven system is 5000 m³. 3 By varying the injection volume of alternating small-segment plugs, the recovery rate under different alternating small-segment plug conditions can be obtained, such as... Figure 7 As shown, the optimal alternating small-segment injection volume is Q. 压驱 The extraction rate is 0.05-0.2 times higher, indicating a better extraction rate.

[0051] At a carbon dioxide injection rate v2 of 350m 3 / day, the oil saturation map is obtained under different formation pressure / minimum miscibility pressure (MMP) ratios after gas injection, as shown in the figure. Figure 8 As shown, the oil saturation in the middle blue area is 0, and the oil saturation in the outer red area is 0.38. As the formation pressure / minimum miscibility pressure (MMP) ratio increases, the oil saturation around the well decreases. When the target reservoir pressure is 1.3-1.6 times the minimum miscibility pressure (MMP), the oil saturation around the well is low, and the carbon dioxide sweep range is large.

[0052] Triaxial stress core displacement experiments are an experimental method used to study the fluid displacement behavior of rocks under triaxial stress conditions. By simulating the triaxial stress conditions of underground oil reservoirs, the effects of these stress conditions on core permeability, fluid saturation, and oil displacement efficiency are investigated. The experiment requires specialized equipment to apply triaxial stress, including a hydraulic system, stress loading device, and measuring equipment. These devices can generate stress in three directions. By measuring the stress, strain, and other mechanical properties of the rock samples, the compressive strength, shear strength, and failure mechanism of the rock can be analyzed. Figure 9 As shown, the permeability changes under different axial pressures are obtained. Microfractures are formed when the pressure injected into the formation is 0.8 to 0.95 times the formation fracture pressure. If the stress is too high, large main fractures are formed, which can easily cause channeling of the injected medium.

[0053] During reservoir development, as formation fluids are extracted, the effective stress on the rock skeleton increases, leading to rock deformation and changes in porosity. Core nuclear magnetic resonance in-situ displacement experiments are a method using nuclear magnetic resonance (NMR) technology to study the fluid behavior of cores under reservoir conditions. This experiment can observe the migration of injected fluids in porous rocks during displacement and calculate fundamental core parameters such as porosity, permeability, and average pore throat radius by extracting T2 spectra. High-pressure porosity experiments, such as... Figure 10As shown, the specific porosity is the porosity under different effective stresses / initial porosity. In the pressure-driven water injection and pressurization stage of core 1, the relative porosity increases by 1% when the effective stress decreases from 28.51 MPa to -5.51 MPa. In the pressure-driven water injection and pressurization stage of core 2, the relative porosity increases by 0.5% when the effective stress decreases from 28.58 MPa to -5.45 MPa. Therefore, the high-pressure expansion rate K ranges from 0.5% to 1%.

[0054] 2. Alternating pressure-driven injection scheme design

[0055] Total injection volume Q 压驱 =C t V(P 目标 -P 目前 ); where C t The comprehensive compressibility coefficient is given by V, where V is the reservoir volume and P is the total compressibility coefficient. 目标 To restore formation pressure as expected, P 目前 This represents the current formation pressure.

[0056] reservoir volume Where N is the geological reserves, m 3 ; Porosity; S oi This represents the original oil saturation.

[0057] Overall compression ratio Among them, C f The rock compressibility coefficient is given in MPa. -1 C o The compressibility coefficient of the oil is expressed in MPa. -1 C W Let be the compressibility coefficient of water, in MPa. -1 S oi Original oil saturation; S wi To bind water saturation; denoted as porosity; K represents the high-pressure expansion rate.

[0058] Specifically, the minimum miscibility pressure of crude oil and CO2 in the target well reservoir is obtained. The minimum miscibility pressure of formation crude oil and CO2 refers to the pressure at which the oil and gas phases reach miscibility under certain pressure and temperature conditions, when the interfacial tension between the two phases is zero. This pressure is the minimum miscibility pressure for carbon dioxide miscible displacement. The minimum miscibility pressure of formation crude oil and CO2 can be tested according to the method specified in standard SY / T6573-2003 "Determination of Minimum Miscibility Pressure by Capillary Test". The pressure corresponding to the inflection point in the crude oil recovery curve obtained through a series of displacement experiments is the minimum miscibility pressure. In this embodiment, the CO2 displacement efficiency curves of capillary tests under different reservoir pressures are shown below. Figure 11As shown in the figure, the minimum miscibility pressure of crude oil-CO2 in the target oil well reservoir is 38 MPa, and the expected formation pressure to be recovered is 57.8 MPa (1.52 times the minimum miscibility pressure).

[0059] The overall compressibility of the target oil well:

[0060]

[0061] Among them, C f The rock compressibility coefficient is given in MPa. -1 C o The compressibility coefficient of the oil is expressed in MPa. -1 C W Let be the compressibility coefficient of water, in MPa. -1 S oi Original oil saturation; S wi To bind water saturation; denoted as porosity; K represents the high-pressure expansion rate.

[0062] Reservoir volume of the target oil well

[0063] Where V is the reservoir volume, m 3 N represents geological reserves, m 3 ; Porosity; S oi denoted as the original oil saturation; K represents the high-pressure pore expansion rate.

[0064] Total injection volume Q of the target oil well under pressure drive 压驱 =C t V(P 目标 -P 目前 )=0.000281862275×1161655×(57.8-26)=10400m 3 ;

[0065] Among them, Q 压驱 m is the total injection volume of the pressure drive. 3 C t The overall compressibility factor is expressed in MPa. -1 V represents the reservoir volume, in meters. 3 ;P 目标 To restore formation pressure as expected, MPa; P 目前 The current formation pressure is in MPa.

[0066] Therefore, the total underground pressure-driven injection volume is 10400 m³. 3 The underground pressure-driven water injection volume is 5200 m³. 3 Formation pressure-driven carbon dioxide injection volume 5200 m³ 3 Converted to 3640 m³ of liquid carbon dioxide at ground level3 The alternating small-segment plug injection volume is 0.1Q. 压驱， The alternating small-segment injection volume is approximately 1000 cubic meters of formation volume. That is, 1000 cubic meters of groundwater and 1000 cubic meters of underground carbon dioxide are injected alternately.

[0067] The groundwater volume is 1000 cubic meters, meaning the surface water injection segment is 1000 cubic meters. The underground carbon dioxide volume is 1000 cubic meters, and the carbon dioxide density under the geological conditions is 0.7 g / m³. 3 Ground carbon dioxide density is 1.0 g / m³ 3 Equivalent to 700m³ of liquid carbon dioxide at ground level 3 Ground injection at 1000m 3 Water - 700m 3 Liquid CO2 is injected alternately. The injection sequence for the surface sluice block is: 1000m... 3 Water - 700m 3 CO2—1000m 3 Water - 700m 3 CO2—1000m 3 Water - 700m 3 CO2—1000m 3 Water - 700m 3 CO2—1000m 3 Water - 700m 3 CO2—200m 3 Water - 140m 3 CO2.

[0068] 3. Field Application

[0069] 1000m from the ground 3 Water - 700m 3 Liquid CO2 is injected alternately via slug injection at an optimized injection rate of 500 m / s. 3 Injection was carried out daily for two consecutive days. During the injection process, the injection rate was controlled by monitoring changes in bottom-hole pressure, maintaining the bottom-hole pressure between 57.8 and 68.7 MPa. At this point, microfractures were formed in the reservoir through hydraulic fracturing, thus improving the reservoir's permeability. The surface carbon dioxide injection rate was 350 m³ / h. 3 Injection was performed continuously for two days, with each two-day injection constituting one slug. Water and carbon dioxide were alternately injected via pressure-driven injection, ensuring a 1:1 ratio between the volume of the groundwater slug and the total volume of the underground carbon dioxide slug. During pressure-driven injection, the well was shut off. Injection ceased and the injection well was shut off after the designed total injection volume was completed. The well was reopened when the oil pressure change rate was ≤0.1 MPa / d. This well group cumulatively increased oil production by 600 tons, enhancing the recovery rate by 12.5%.

[0070] Comparative Example 1: Pressure-driven water injection development of low-permeability reservoirs

[0071] The pressure-driven well in this comparative example is located in the same block as the pressure-driven well in Example 1, and the development formation is the same. It uses pressure-driven water injection for development, and the specific steps include:

[0072] At 500m 3 Water is injected at a rate of / day, continuously. During the injection process, the injection rate is controlled by monitoring changes in bottom-hole pressure, maintaining the bottom-hole pressure between 57.8-68.7 MPa. At this point, microfractures are formed in the reservoir through hydraulic fracturing, thus improving the reservoir's permeability. The designed hydraulic fracturing injection volume of 10400 m³ is completed. 3 Injection was then stopped and the injection well was shut down. The well was reopened when the oil pressure change rate of the injection well was ≤0.1 MPa / d. This well group cumulatively increased oil production by 300 tons, enhancing the recovery rate by 5.5%.

[0073] Depend on Figure 12 It can be seen that implementing water-gas alternating pressure drive increases the recovery rate by 12.5%; implementing pressure drive alone with water injection increases the recovery rate by 5.5%; indicating that water-gas alternating pressure drive has a strong oil-enhancing capacity and higher economic efficiency.

[0074] The above description is merely a preferred embodiment of the present invention, but the scope of protection of the present invention is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the embodiments of the present invention should be included within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for oil recovery from low-permeability reservoirs using alternating pressure flooding, characterized in that: Includes the following steps: (1) The total injection volume of the pressure drive is obtained based on the comprehensive compressibility coefficient of the target reservoir, reservoir volume, expected recovery formation pressure, and current formation pressure. (2) Based on the physical properties of the target reservoir and the formation fluid properties, a three-dimensional numerical model is constructed. Under the constraints of the total injection volume of the pressure drive and the formation micro-fracture pressure, the correspondence between the injection rate of water or carbon dioxide and the degree of recovery is determined, and the optimal injection rate is selected. (3) Use the total injection volume of the pressure drive obtained in step (1) and the optimal injection rate obtained in step (2) to determine the optimal alternating slug injection volume and volume ratio; (4) Based on the optimal injection rate obtained in step (2) and the optimal alternating slug injection volume and volume ratio obtained in step (3), water and carbon dioxide are injected alternately by slug pressure drive. After the total injection volume of pressure drive is injected, the injection is stopped and the injection well is closed. When the oil pressure change rate of the target oil well is ≤0.1MPa / d, the oil well production is started.

2. The alternating pressure flooding method for oil recovery in low-permeability reservoirs according to claim 1, characterized in that: The formula for calculating the total injection volume of the pressure drive is as follows: Q 压驱 =C t V(P 目标 -P 目前 ); where Q 压驱 m is the total injection volume of the pressure drive. 3 C t The overall compressibility factor is expressed in MPa. -1 V represents the reservoir volume, in meters. 3 ;P 目标 To restore formation pressure as expected, MPa; P 目前 The current formation pressure is in MPa.

3. The alternating pressure flooding method for oil recovery in low-permeability reservoirs according to claim 2, characterized in that: The P 目标 The minimum miscibility pressure of crude oil and carbon dioxide in the target oil well is 1.3 to 1.6 times.

4. The alternating pressure flooding method for oil recovery in low-permeability reservoirs according to claim 1, characterized in that: The formation microfracture pressure includes the formation microfracture pressure P induced by water injection. w1 Carbon dioxide injection induces formation microfracture pressure P w2 The P w1 The formation fracturing pressure P caused by water injection 破裂1 0.8 to 0.95 times; the P w2 The formation fracturing pressure P caused by carbon dioxide injection 破裂2 0.8 to 0.95 times that.

5. The alternating pressure flooding method for oil recovery in low-permeability reservoirs according to claim 2 or 3, characterized in that: The formula for calculating V is: Where V is the reservoir volume, m 3 N represents geological reserves, m 3 ; Porosity; S oi denoted as the original oil saturation; K represents the high-pressure pore expansion rate.

6. The alternating pressure flooding method for oil recovery in low-permeability reservoirs according to claim 5, characterized in that: The value of K is 0.5-1%.

7. The alternating pressure flooding method for oil recovery in low-permeability reservoirs according to claim 6, characterized in that: The formula for calculating the overall compression coefficient is as follows: Among them, C f The rock compressibility coefficient is expressed in MPa. -1 C o The compressibility coefficient of the oil is expressed in MPa. -1 C W Let be the compressibility coefficient of water, in MPa. -1 S oi Original oil saturation; S wi To bind water saturation; denoted as porosity; K represents the high-pressure expansion rate.

8. The alternating pressure flooding method for oil recovery in low-permeability reservoirs according to any one of claims 1 to 4, characterized in that: The average permeability of the low-permeability reservoir is <10.0×10⁻⁶. -3 μm 2 .

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