Oil and gas exploitation method

Abstract

The invention relates to the field of oil and gas exploration and development, and discloses an oil and gas exploitation method which comprises the following steps: determining the fracture pressure of a target stratum according to a rock core fracture pressure experiment, and determining the bottom hole pressure of an injection well based on the fracture pressure; according to the flow of the output of the output well, the flow of the injection fluid of the injection well is determined; obtaining target data, and calculating a target well distance between the injection well and the output well based on the target data; and deploying the injection well and the output well based on the target well spacing, and performing oil and gas exploitation based on the bottom hole pressure of the injection well and the flow of the injection fluid of the injection well. Based on the scheme, the oil and gas exploitation process can be integrated into one stage, so that the oil and gas exploitation time can be shortened, and the exploitation cost is reduced.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas exploration and development, in particular to an oil and gas production method. BACKGROUND

[0002] At present, the development process of conventional oil and gas generally includes a natural capacity depletion development stage, a water injection secondary development stage and a supplemental energy development stage.

[0003] At the initial production, the oil and gas well can generally rely on the natural capacity (i.e. the underground pressure) inside the formation to push the oil and gas out of the formation. With the passage of time, the underground pressure gradually decreases, and the oil and gas production begins to gradually decrease, thereby entering the natural capacity depletion development stage. In order to improve the oil and gas recovery, maintain the oilfield productivity and prolong the production cycle of the oil and gas well, the conventional oil and gas field will further inject water or other liquids, thereby entering the water injection secondary development stage. At this stage, the injected water or other liquids can maintain the underground pressure and push the remaining oil and gas to the production well, thereby increasing the production. When the effect of the water injection secondary development gradually decreases, in order to further improve the recovery and maintain the productivity, other supplemental energy development measures, such as the pressure boosting technology, CO2 injection, polymer flooding, etc., are usually introduced, thereby entering the supplemental energy development stage.

[0004] However, the above development process of the conventional oil and gas causes a long duration of oil and gas production and a high cost of production. SUMMARY

[0005] The present application aims to overcome the problem of long duration of oil and gas production and high cost of production in the prior art, and provides an oil and gas production method.

[0006] In order to achieve the above-mentioned purpose, the present application provides an oil and gas production method, comprising:

[0007] According to the core fracture pressure experiment, the fracture pressure of the target formation is determined, and based on the fracture pressure, the bottom hole pressure of the injection well is determined;

[0008] According to the flow rate of the production of the production well, the flow rate of the injection fluid of the injection well is determined;

[0009] Target data is obtained, and the target well spacing between the injection well and the production well is calculated based on the target data, wherein the target data includes the target formation fluid viscosity, the target formation permeability, the target formation fluid volume coefficient, the relative permeability of the injection fluid, the target starting pressure gradient of the injection fluid, the target flow resistance gradient of the injection fluid, the wellbore radius of the injection well, the oil and gas layer size of the target formation and the bottom hole fluid pressure of the production well;

[0010] deploy the injection well and the production well based on the target well spacing, and perform oil and gas exploitation based on a bottom hole pressure of the injection well and a flow rate of the injection fluid of the injection well.

[0011] In the embodiments of the present application, before the target data is acquired and the target well spacing between the injection well and the production well is calculated based on the target data, the method further comprises:

[0012] According to a core start-up pressure experiment, a corresponding relationship between a start-up pressure gradient of the injection fluid and a first ratio is determined, the first ratio being a ratio of a formation permeability to a viscosity of the injection fluid.

[0013] Based on the corresponding relationship, a target start-up pressure gradient of the injection fluid is determined.

[0014] In the embodiments of the present application, the start-up pressure gradient of the injection fluid is calculated based on the following formula:

[0015]

[0016] wherein D is the start-up pressure gradient of the injection fluid, in MPa / m; ΔP1 is a pressure difference between a fluid pressure at an injection end of the core fluid and a fluid pressure at a discharge end of the core fluid, in MPa; and L1 is a length of the core, in m.

[0017] In the embodiments of the present application, before the target data is acquired and the target well spacing between the injection well and the production well is calculated based on the target data, the method further comprises:

[0018] According to a fluid flow resistance experiment, a corresponding relationship between a flow resistance gradient of the injection fluid and a first ratio is determined, the first ratio being a ratio of a formation permeability to a viscosity of the injection fluid.

[0019] Based on the corresponding relationship, a target flow resistance gradient of the injection fluid is determined.

[0020] In the embodiments of the present application, the flow resistance gradient of the injection fluid is calculated based on the following formula:

[0021]

[0022] wherein E is the flow resistance gradient of the injection fluid, in MPa / d; ΔP2 is a pressure difference between a fluid pressure at an injection end of the core fluid and a fluid pressure at a discharge end of the core fluid, in MPa; Q1 is a flow rate of the fluid discharged at the discharge end of the core fluid per unit time, in m 3 / d; S1 is a cross-sectional area of the core, in m 2 ; and L1 is a length of the core, in m.

[0023] In the embodiment of the present application, the fracture pressure of the target formation is determined based on the core fracture pressure test, including:

[0024] Recording the first moment corresponding to the abnormal increase in flow rate at the core fluid discharge end, and using the pressure at the core fluid injection end corresponding to the moment before and closest to the first moment as the fracture pressure of the target formation;

[0025] Alternatively, the second moment corresponding to the abnormal decrease in pressure at the core fluid injection end is recorded, and the pressure at the core fluid injection end corresponding to the moment before and closest to the second moment is used as the fracture pressure of the target formation;

[0026] Alternatively, the third moment corresponding to the acoustic wave value being higher than the acoustic wave background value is recorded, and the pressure at the core fluid injection end corresponding to the moment before and closest to the third moment is used as the fracture pressure of the target formation.

[0027] In an embodiment of the present application, determining the bottom hole pressure of the injection well based on the fracture pressure includes:

[0028] The bottom hole pressure of the injection well is controlled to be lower than the fracture pressure.

[0029] In the embodiment of the present application, determining the flow rate of the injected fluid of the injection well according to the flow rate of the output of the production well includes:

[0030] The flow rate of the injected fluid of the injection well is controlled to be greater than or equal to the flow rate of the output of the production well.

[0031] In the embodiment of the present application, when the injection well is a vertical well, the oil and gas layer of the target formation

[0032] Dimensions include the thickness of the oil and gas formation;

[0033] When the injection well is a directional well, a horizontal well or a horizontal branch well, the oil and gas layer size of the target formation includes the length of the oil and gas layer.

[0034] In the embodiment of the present application, the target well distance between the injection well and the production well is calculated based on the target data according to the following formula:

[0035]

[0036] Where q is the flow rate of the injected fluid in the injection well per unit time, in m 3 / d; k is the permeability of the target formation, in μm 2 ;k ris the relative permeability of the injection fluid; h is the oil and gas layer thickness or length of the target formation, in m; P i is the bottom hole pressure of the injection well, in MPa; P wf is the bottom hole fluid pressure of the production well, in MPa; Do is the target threshold pressure gradient of the injection fluid, in MPa / m; r i is the wellbore radius of the injection well, in m; x is the distance from the center of the injection well, in m; L is the target well spacing between the injection well and the production well, in m; Eo is the target flow resistance gradient of the injection fluid, in MPa / d; μ is the viscosity of the fluid in the target formation, in mPa.s; B is the volume factor of the fluid in the target formation.

[0037] In the embodiment of the present application, the method further comprises:

[0038] determining the maximum well spacing between the injection well and the production well.

[0039] In the embodiment of the present application, the maximum well spacing between the injection well and the production well is determined based on the following formula:

[0040]

[0041] wherein, L max is the maximum distance between the injection well and the production well, in m; P i is the bottom hole pressure of the injection well, in MPa; P wf is the bottom hole fluid pressure of the production well, in MPa; Do is the target threshold pressure gradient of the injection fluid, in MPa / m; r i is the wellbore radius of the injection well, in m; h is the oil and gas layer thickness or length of the target formation, in m; q is the injection fluid flow rate of the injection well per unit time, in m 3 / d; Eo is the target flow resistance gradient of the injection fluid,

[0042] in MPa / d.

[0043] In the embodiment of the present application, the maximum well spacing between the injection well and the production well is determined based on the following formula:

[0044]

[0045] wherein, x is the distance from the center of the injection well, in m; r i is the wellbore radius of the injection well, in m; L max is the maximum distance between the injection well and the production well, in m; h is the oil and gas layer thickness or length of the target formation, in m; q is the injection fluid flow rate of the injection well per unit time, in m 3 / d; Eo is the target flow resistance gradient of the injection fluid, in MPa / d; P i P is the bottom hole pressure of the injection well, in MPa; P wf P is the bottom hole fluid pressure of the production well, in MPa; Do is the target starting pressure gradient of the injection fluid, in MPa / m.

[0046] In the embodiments of the present application, the injection well adopts a casing perforation completion mode or a screen completion mode, and the production well adopts a casing perforation completion mode.

[0047] Through the technical solution, the technical solution comprises: determining the fracture pressure of the target formation according to a core fracture pressure experiment, determining the bottom hole pressure of the injection well based on the fracture pressure; determining the flow rate of the injection fluid of the injection well according to the flow rate of the production of the production well; obtaining target data, calculating the target well spacing of the injection well and the production well based on the target data, the target data comprising the target formation fluid viscosity, the target formation permeability, the target formation fluid volume coefficient, the relative permeability of the injection fluid, the target starting pressure gradient of the injection fluid, the target flow resistance gradient of the injection fluid, the wellbore radius of the injection well, the oil and gas layer size of the target formation, and the bottom hole fluid pressure of the production well; deploying the injection well and the production well based on the target well spacing, and carrying out oil and gas exploitation based on the bottom hole pressure of the injection well and the flow rate of the injection fluid of the injection well. Based on the scheme provided in the embodiments of the present application, the oil and gas exploitation process can be integrated into one stage, so that the oil and gas exploitation time can be shortened and the exploitation cost can be reduced.

[0048] Other features and advantages of the embodiments of the present application will be described in detail in the following specific embodiments. BRIEF DESCRIPTION OF DRAWINGS

[0049] The accompanying drawings are included to provide a further understanding of the embodiments of the present application, and constitute a part of the specification, and are used together with the following specific embodiments to explain the embodiments of the present application, but do not constitute a limitation on the embodiments of the present application. In the drawings:

[0050] Figure 1 The flowchart of the oil and gas exploitation method according to the embodiments of the present application is schematically shown;

[0051] Figure 2 The well layout diagram according to the embodiments of the present application is schematically shown;

[0052] Figure 3 Another well layout diagram according to the embodiments of the present application is schematically shown;

[0053] Figure 4 Another well layout diagram according to the embodiments of the present application is schematically shown;

[0054] Figure 5 Fig. 16 schematically illustrates yet another well layout according to embodiments of the present application;

[0055] Figure 6 Fig. 17 schematically illustrates yet another well layout according to embodiments of the present application;

[0056] Figure 7 Fig. 18 schematically illustrates yet another well layout according to embodiments of the present application;

[0057] Figure 8 Fig. 19 schematically illustrates yet another well layout according to embodiments of the present application;

[0058] Figure 9 Fig. 20 schematically illustrates yet another well layout according to embodiments of the present application;

[0059] Figure 10 Fig. 21 schematically illustrates yet another well layout according to embodiments of the present application;

[0060] Figure 11 Fig. 22 schematically illustrates yet another well layout according to embodiments of the present application;

[0061] Figure 12 Fig. 23 schematically illustrates yet another well layout according to embodiments of the present application;

[0062] Figure 13 Fig. 24 schematically illustrates a correspondence between a first ratio and a starting pressure gradient for injecting a fluid according to embodiments of the present application;

[0063] Figure 14 Fig. 25 schematically illustrates a correspondence between a second ratio and a flow resistance gradient for injecting a fluid at different first ratios according to embodiments of the present application. DETAILED DESCRIPTION

[0064] In order to make the objectives, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be described clearly and completely below with reference to the drawings in the embodiments of the present application. It should be understood that the specific embodiments described herein are merely intended to illustrate and explain the embodiments of the present application, and are not intended to limit the embodiments of the present application. Based on the embodiments in the present application, all other embodiments obtained by those of ordinary skill in the art without creative effort belong to the scope of protection of the present application.

[0065] It should be noted that if the embodiments of the present application involve directionality indication (such as up, down, left, right, front, back, etc.), the directionality indication is only used to explain the relative position relationship, motion condition, etc. between components in a certain posture (as shown in the drawings), and if the certain posture changes, the directionality indication also changes accordingly.

[0066] In addition, if the embodiments of the present application involve descriptions such as "first", "second", etc., the descriptions of "first", "second", etc. are only for description purposes and cannot be understood as indicating or implying the relative importance of the indicated technical features or implicitly indicating the number of the indicated technical features. Therefore, the features limited by "first", "second" can explicitly or implicitly include at least one of the features. In addition, the technical solutions of each embodiment can be combined with each other, but it must be based on the realization of a person skilled in the art, and when the combination of technical solutions contradicts each other or cannot be realized, it should be considered that the combination of technical solutions does not exist and is not within the protection scope required by the present application.

[0067] As described in the background, the conventional oil and gas development process usually includes a natural capacity depletion development stage, a water injection secondary development stage and a supplemental energy development stage, resulting in a long duration of oil and gas production and high production cost.

[0068] In view of this, one embodiment of the present application provides an oil and gas production method, as shown in the figure, which can include the following steps: Figure 1 As shown in the figure, the oil and gas production method can include the following steps:

[0069] Step 101: Determine the fracture pressure of the target formation according to the core fracture pressure experiment, and determine the bottom hole pressure of the injection well based on the fracture pressure.

[0070] To accurately determine the fracture pressure of the target formation, a core fracture pressure experiment can be performed under the conditions of the target formation. Specifically, the confining pressure of the experimental core can be set as the overburden pressure of the target formation, the fluid pressure of the core can be set as the fluid pressure of the target formation, and the core temperature can be set as the temperature of the target formation. The experimental process is as follows: keep the fluid pressure of the fluid discharge end of the core constant and the same as the fluid pressure of the target formation, inject fluid into the fluid injection end of the core, and gradually increase the fluid pressure of the fluid injection end of the core, when the core breaks, measure the fluid pressure of the fluid injection end of the core, which is the fracture pressure of the target formation.

[0071] In the embodiments of the present application, the fracture pressure of the target formation can be measured in combination with the pressure difference correlation method, the acoustic wave detection method, etc.

[0072] In the case of the combined pressure difference joint measurement method, the fracture pressure of the target formation is determined according to the core fracture pressure experiment, which can include: recording a first time corresponding to an abnormal increase in the flow rate of the core fluid discharge end, and taking the pressure of the core fluid injection end at a time closest to the first time as the fracture pressure of the target formation; or recording a second time corresponding to an abnormal decrease in the pressure of the core fluid injection end, and taking the pressure of the core fluid injection end at a time closest to the second time as the fracture pressure of the target formation.

[0073] That is, in specific implementation, the flow rate of the core fluid discharge end, the pressure of the core fluid injection end, and the pressure of the core fluid discharge end can be detected in real time, and when the flow rate of the core fluid discharge end suddenly increases, the pressure of the core fluid injection end corresponding to a time before the sudden increase in the flow rate is taken as the fracture pressure. Or, when the pressure of the core fluid injection end suddenly decreases, the pressure of the core fluid injection end corresponding to a time before the sudden decrease in the pressure is taken as the fracture pressure.

[0074] In the case of the combined acoustic wave detection method, the fracture pressure of the target formation is determined according to the core fracture pressure experiment, which can include: recording a third time corresponding to an acoustic wave value higher than an acoustic wave background value, and taking the pressure of the core fluid injection end at a time closest to the third time as the fracture pressure of the target formation.

[0075] That is, in specific implementation, the acoustic wave value of the core can be detected in real time, and when the acoustic wave value suddenly becomes higher than the acoustic wave background value, the pressure of the core fluid injection end corresponding to a time before the sudden increase in the acoustic wave value is taken as the fracture pressure.

[0076] In the embodiments of the present application, the bottom hole pressure of the injection well is determined based on the fracture pressure, which can include: controlling the bottom hole pressure of the injection well to be less than the fracture pressure. Preferably, the bottom hole pressure of the injection well can be controlled to be less than 95% of the fracture pressure, or the bottom hole pressure of the injection well can be controlled to be less than 2 MPa of the fracture pressure. In this way, the problem of fluid stringing in the formation due to the over-high fluid injection pressure causing the formation to crack and generate cracks during the injection process can be avoided.

[0077] In actual application, in order to accurately obtain the fracture pressure of the target formation, a core with a larger volume can be used when performing the core fracture pressure experiment. In addition, the fluid injected into the core fluid injection end can have the same properties as the injection fluid used in the subsequent step 104 of oil and gas production.

[0078] Step 102: determining the flow rate of the injection fluid of the injection well according to the flow rate of the production of the production well.

[0079] It can be understood that the production well corresponds to the injection well. In a specific implementation, the flow rate of the injection fluid of the injection well per unit time can be determined according to the flow rate of the production of the production well per unit time.

[0080] The flow rate of the production of the production well per unit time can be determined according to the full equivalent barrel oil cost and the production cycle.

[0081] In the embodiment of the present application, determining the flow rate of the injection fluid of the injection well according to the flow rate of the production of the production well can include: controlling the flow rate of the injection fluid of the injection well to be greater than or equal to the flow rate of the production of the production well. That is, the flow rate of the injection fluid of the injection well per unit time can be controlled to be greater than or equal to the flow rate of the production of the production well per unit time.

[0082] In step 103, target data is obtained, and a target well spacing between the injection well and the production well is calculated based on the target data.

[0083] The target data can include target formation fluid viscosity, target formation permeability, target formation fluid volume coefficient, relative permeability of the injection fluid, target threshold pressure gradient of the injection fluid, target flow resistance gradient of the injection fluid, wellbore radius of the injection well, oil and gas layer size of the target formation, and bottom hole fluid pressure of the production well.

[0084] In actual application, the target formation permeability can be obtained by core experiment measurement under target formation conditions or logging data, the relative permeability of the injection fluid can be obtained by simulating core relative permeability experiment measurement of the injection fluid under target formation conditions, the wellbore radius of the injection well and the oil and gas layer size of the target formation can be obtained by drilling and logging data, the bottom hole fluid pressure of the production well can be obtained according to production mode and field test data of the production well, and the target formation fluid viscosity and the target formation fluid volume coefficient can be obtained by experiment measurement of the formation fluid and the injection fluid under target formation conditions.

[0085] The oil and gas layer size of the target formation is related to the drilling mode of the injection well. When the injection well is a straight well, the oil and gas layer size of the target formation can include the thickness of the oil and gas layer; when the injection well is a directional well, a horizontal well or a horizontal branch well, the oil and gas layer size of the target formation can include the length of the oil and gas layer.

[0086] When using natural flow production or gas lift production, the bottom hole flowing pressure of the production well can be the sum of the wellhead pressure and the pressure of the fluid column from the wellhead to the bottom hole. When using pump production, the bottom hole flowing pressure of the production well can be the pressure of the fluid column from the position of the pump to the oil and gas production section of the production well.

[0087] To obtain the target starting pressure gradient of the injection fluid, before step 103, the oil and gas exploitation method provided by the embodiment of the present application further comprises steps one and two, which are specifically as follows:

[0088] Step one, according to the core starting pressure experiment, a corresponding relationship between the starting pressure gradient of the injection fluid and a first ratio is determined, the first ratio being a ratio of the formation permeability to the viscosity of the injection fluid.

[0089] To accurately determine the target starting pressure gradient of the injection fluid, the core starting pressure experiment can be performed under the target formation condition. Specifically, the experimental core can be saturated with oil and gas under the target formation pressure and the target formation temperature, the temperature of the core is set to the target formation temperature, the confining pressure of the core is set to the overburden pressure of the target formation, and the fluid pressure of the core is set to the fluid pressure of the target formation. Moreover, the length L1, the cross-sectional area S1 and the permeability K1 of the core are measured. The experimental process is as follows: the fluid pressure of the fluid injection end of the core is kept constant and the same as the fluid pressure of the target formation, the fluid is injected into the fluid injection end of the core, and the fluid pressure of the fluid injection end of the core is gradually increased, the fluid pressure P1 of the fluid injection end of the core is measured when the fluid starts to be discharged from the fluid discharge end of the core.

[0090]

[0091] Further, according to the pressure difference ΔP1 between the fluid pressure P1 of the fluid injection end of the core and the fluid pressure P2 of the fluid discharge end of the core when the fluid starts to be discharged from the fluid discharge end of the core, ΔP1=P1-P2; the starting pressure gradient of the injection fluid is calculated based on the following formula (1):

[0092]

[0093] Wherein, D is the starting pressure gradient of the injection fluid, the unit being MPa / m; ΔP1 is the pressure difference between the fluid pressure of the fluid injection end of the core and the fluid pressure of the fluid discharge end of the core, the unit being MPa; L1 is the length of the core, the unit being m.

[0094] In the specific experiment, to establish an accurate corresponding relationship to accurately obtain the target starting pressure gradient of the injection fluid, the fluid injected into the fluid injection end of the core can be the same as the injection fluid used in the subsequent step 104 for oil and gas exploitation. Thus, the ratio of the formation permeability to the viscosity of the injection fluid corresponding to the above starting pressure gradient can be obtained, and the formation permeability is the permeability of the core.

[0095] Then, by performing the above core starting pressure experiment on cores with different permeabilities, the corresponding relationship between the starting pressure gradient of the injection fluid and the first ratio can be obtained.

[0096] ​Step two, determining the target starting pressure gradient of the injection fluid based on the corresponding relationship.

[0097] After obtaining the corresponding relationship in step one, the target starting pressure gradient of the injection fluid can be determined according to the target formation permeability, the viscosity of the injection fluid and the corresponding relationship.

[0098] To obtain the target flow resistance gradient of the injection fluid, before step 103, the oil and gas exploitation method provided in the embodiments of the present application further comprises steps ① and ②, which are specifically as follows:

[0099] Step ①, determining the corresponding relationship between the flow resistance gradient of the injection fluid and the first ratio according to the fluid flow resistance experiment, the first ratio being the ratio of the formation permeability to the viscosity of the injection fluid.

[0100] The flow resistance gradient of the injection fluid is the flow resistance gradient of unit injection fluid flow in unit flow cross-sectional area. The target flow resistance gradient of the injection fluid is the target flow resistance gradient of unit injection fluid flow in unit flow cross-sectional area.

[0101] In the embodiments of the present application, the corresponding relationship between the flow resistance gradient of the injection fluid and the first ratio can be specifically the corresponding relationship between the flow resistance gradient of the injection fluid and the second ratio under different first ratios, the second ratio being the ratio of unit injection fluid flow to unit flow cross-sectional area.

[0102] To accurately determine the target flow resistance gradient of the injection fluid, the fluid flow resistance experiment can be performed under the target formation conditions. Specifically, the experimental core can be saturated with oil and gas under the target formation pressure and the target formation temperature, the core temperature can be set to the target formation temperature, the confining pressure of the core can be set to the target formation overburden pressure, and the fluid pressure of the core can be set to the target formation fluid pressure. Moreover, the length L1, the cross-sectional area S1 and the permeability K1 of the core can be measured. The experimental process is as follows: the fluid pressure at the fluid discharge end of the core is kept constant and the same as the target formation fluid pressure, the fluid is injected into the fluid injection end of the core, the fluid pressure at the fluid injection end of the core is changed, the pressure difference ΔP2 between the fluid pressure P1 at the fluid injection end of the core and the fluid pressure P2 at the fluid discharge end of the core is measured, ΔP2=P1-P2, and the flow rate Q1 of the fluid discharged from the fluid discharge end of the core per unit time is measured.

[0103] The flow resistance gradient of the injection fluid is calculated based on the following formula (2):

[0104]

[0105] E=ΔP2Q1S1L1 3 S1 is the cross-sectional area of the core, m 2 L1 is the length of the core, m.

[0106] In the specific experiment, in order to establish an accurate corresponding relationship to accurately obtain the target flow resistance gradient of the injected fluid, the fluid injected into the core fluid injection end can be the same as the injected fluid used in the subsequent step 104 for oil and gas production. Thus, the ratio of the formation permeability to the injected fluid viscosity corresponding to the above flow resistance gradient can be obtained, and the formation permeability is the permeability of the core.

[0107] Then, by performing the fluid flow resistance experiment on the cores with different permeabilities, the corresponding relationship between the flow resistance gradient of the injected fluid and the first ratio can be obtained.

[0108] Step 2, based on the corresponding relationship, determining the target flow resistance gradient of the injected fluid.

[0109] After obtaining the corresponding relationship through step 1, the target starting pressure gradient of the injected fluid can be determined according to the target formation permeability, the viscosity of the injected fluid, the second ratio, and the corresponding relationship.

[0110] In actual application, for each core, the pressure difference ΔP1 between the fluid pressure P1 of the core fluid injection end and the fluid pressure P2 of the core fluid discharge end when the core fluid discharge end begins to discharge fluid can be obtained through step 1, and then the fluid pressure of the core fluid injection end is changed, and the pressure difference ΔP2 between the fluid pressure P1 of the core fluid injection end and the fluid pressure P2 of the core fluid discharge end is measured to calculate the flow resistance gradient of the injected fluid. Further, for each core, the corresponding starting pressure gradient of the injected fluid and the flow resistance gradient of the injected fluid can be obtained. By performing the core starting pressure experiment and the fluid flow resistance experiment on the cores with different permeabilities, the corresponding relationship between the starting pressure gradient of the injected fluid and the flow resistance gradient of the injected fluid can also be established.

[0111] In the embodiment of the present application, step 103 calculates the target well spacing between the injection well and the production well based on the target data, which can be performed according to the following formula (3):

[0112]

[0113] Wherein q is the flow rate of the injected fluid of the injection well per unit time, m3 dk is the target formation permeability, in units of pm 2 , specifically x 10 -3 pm 2 ; k r is the relative permeability of the injection fluid; h is the oil and gas layer thickness or length of the target formation, in units of m; P i is the bottom hole pressure of the injection well, in units of MPa; P wf is the bottom hole fluid pressure of the production well, in units of MPa; Do is the target threshold pressure gradient of the injection fluid, in units of MPa / m; r i is the wellbore radius of the injection well, in units of m; x is the distance from the center of the injection well, in units of m; L is the target well spacing between the injection well and the production well, which can specifically be the distance from the edge of the injection well to the edge of the production well, in units of m; Eo is the target flow resistance gradient of the injection fluid, in units of MPa / d; p is the viscosity of the target formation fluid, in units of mPa.s; B is the volume coefficient of the target formation fluid.

[0114] Step 104, deploying the injection well and the production well based on the target well spacing, and conducting oil and gas production based on the bottom hole pressure of the injection well and the flow rate of the injection fluid of the injection well.

[0115] That is, the distance between the injection well and the corresponding production well (the distance from the center of the injection wellbore to the center of the production wellbore) can be set as the target well spacing, and then the oil and gas production is conducted based on the bottom hole pressure of the injection well and the flow rate of the injection fluid of the injection well per unit time.

[0116] When conducting oil and gas production, preferably, the molecular weight of the injection fluid used is less than the average molecular weight of the target formation fluid (such as crude oil), and / or the viscosity of the injection fluid used is less than the viscosity of the target formation fluid. Thus, the injection fluid is more easily injected into the target formation, and the oil and gas recovery and resource mobilization rate can be improved.

[0117] For example, the injection fluid can be water, a mixture of surfactant and water, a hydrocarbon liquid, a hydrocarbon gas, nitrogen, carbon dioxide, oxygen-reduced air, etc., and the injection fluid temperature can be lower than, equal to, or higher than the target formation temperature, and the injection fluid is preferably a hydrocarbon gas.

[0118] When the injection fluid is water, normal temperature water, supercritical water, or water vapor can be used.

[0119] When the injection fluid is a mixture of surfactant and water, a mixture of normal temperature surfactant and water, a mixture of surfactant and water with a temperature higher than the target formation temperature, a mixture of surfactant and supercritical water, or a mixture of high-temperature gaseous surfactant and water can be used.

[0120] When the injection fluid is a hydrocarbon liquid, light oil, a liquid hydrocarbon mixture of C15 and below, or a single liquid hydrocarbon can be used.

[0121] When the injection fluid is a hydrocarbon gas, gaseous hydrocarbon gases such as methane, ethane, etc. can be used.

[0122] When the injection fluid is nitrogen, liquid nitrogen or gaseous nitrogen can be used.

[0123] When the injection fluid is carbon dioxide, liquid carbon dioxide or gaseous carbon dioxide can be used.

[0124] When the injection fluid is oxygen-reduced air, to ensure safety, the oxygen content of the oxygen-reduced air used should be lower than the critical oxygen content of the oil-gas and oxygen-reduced air mixture.

[0125] When the injection fluid is a high-temperature fluid, the injection well can be used to inject the target formation after being heated on the ground. Alternatively, a heater can be arranged in the injection well, and the injection fluid at normal temperature can be injected into the injection well and heated by the heater before being injected into the formation.

[0126] In actual applications, nanometer catalysts and / or viscosity reducers can be added to the injection fluid to reduce the viscosity of crude oil or catalyze the cracking of crude oil to produce gas, thereby improving oil displacement efficiency and recovery efficiency.

[0127] It can be understood that the oil and gas exploitation method provided by the embodiments of the present application comprises: determining the fracture pressure of a target formation according to a core fracture pressure experiment, determining the bottom hole pressure of an injection well based on the fracture pressure; determining the flow rate of an injection fluid of the injection well according to the flow rate of the production of a production well; obtaining target data, calculating the target well spacing between the injection well and the production well based on the target data, the target data comprising the viscosity of the fluid of the target formation, the permeability of the target formation, the volume factor of the fluid of the target formation, the relative permeability of the injection fluid, the target starting pressure gradient of the injection fluid, the target flow resistance gradient of the injection fluid, the wellbore radius of the injection well, the size of the oil and gas layer of the target formation, and the bottom hole fluid pressure of the production well; deploying the injection well and the production well according to the target well spacing, and exploiting oil and gas based on the bottom hole pressure of the injection well and the flow rate of the injection fluid of the injection well. Based on the oil and gas exploitation method provided by the embodiments of the present application, the oil and gas exploitation process can be integrated into one stage, thereby shortening the oil and gas exploitation time and reducing the exploitation cost.

[0128] Meanwhile, with the deepening of the conventional oil and gas exploration and development, unconventional oil and gas (especially tight oil and gas and shale oil and gas) becomes an important field of oil and gas exploration and development. However, due to the tight reservoir of tight oil and gas and shale oil and gas, the traditional conventional oil and gas development technology cannot realize the scale benefit development, and the oil and gas recovery rate is low. However, the oil and gas exploitation method provided in the embodiments of the present application can improve the recovery rate of tight oil and gas and shale oil and gas.

[0129] In addition, by determining the optimal well spacing of the injection well and the production well, the problem that the benefit development, the effective use of resources and the reduction of the exploitation cost are difficult to be considered in the prior art is solved.

[0130] In actual application, the oil and gas exploitation method provided in the embodiments of the present application can further include: determining the maximum well spacing of the injection well and the production well; and the step 104 of deploying the injection well and the production well according to the target well spacing includes: calculating the target well spacing according to the maximum investment return rate of the oil and gas exploitation, when the target well spacing is less than or equal to the maximum well spacing, deploying the injection well and the production well according to the target well spacing, that is, taking the target well spacing as the optimal well spacing; and when the target well spacing is greater than the maximum well spacing, deploying the injection well and the production well according to the maximum well spacing, that is, taking the maximum well spacing as the optimal well spacing.

[0131]

[0132] In the calculation of the target well spacing, the flow rate q of the injection fluid of the injection well in a unit time can be set to be the same as the flow rate of the output material of the production well corresponding to the maximum investment return rate of the oil and gas exploitation, that is, the target well spacing corresponding to the maximum investment return rate can be obtained.

[0133] In an implementation manner, the maximum well spacing of the injection well and the production well can be determined based on the following formula (4):

[0134]

[0135] wherein, L max is the maximum distance of the injection well and the production well, and the unit is m; P i is the bottom hole pressure of the injection well, and the unit is MPa; P wf is the bottom hole fluid pressure of the production well, and the unit is MPa; Do is the target starting pressure gradient of the injection fluid, and the unit is MPa / m; r i is the wellbore radius of the injection well, and the unit is m; h is the oil and gas layer thickness or length of the target formation, and the unit is m; q is the flow rate of the injection fluid of the injection well in a unit time, and the unit is m 3 / d; and Eo is the target flow resistance gradient of the injection fluid, and the unit is MPa / d. ​

[0136] In another embodiment, the maximum well spacing between the injection well and the production well can be determined based on the following formula (5):

[0137]

[0138] Where x is the distance from the injection well center, in meters; r i is the wellbore radius of the injection well, in m; L max is the maximum distance between the injection well and the production well, in meters; h is the oil and gas layer thickness or length of the target formation, in meters; q is the flow rate of the injected fluid per unit time in the injection well, in meters 3 / d; Eo is the target flow resistance gradient of the injected fluid, in MPa / d; P i is the bottom hole pressure of the injection well, in MPa; P wf is the bottom hole fluid pressure of the production well, in MPa; Do is the target starting pressure gradient of the injected fluid, in MPa / m.

[0139] When calculating the maximum distance between the injection well and the production well according to formula (4) or formula (5), the flow rate q of the injected fluid per unit time at the injection well can be set to be the same as the flow rate of the output of the production well corresponding to the lowest limit of the oil and gas production investment return. This ensures that the investment return for oil and gas production is above the lowest limit.

[0140] In the embodiments of the present application, the maximum distance refers to the maximum well spacing that allows for safe extraction. When the target well spacing corresponding to the maximum return on investment is less than or equal to the maximum well spacing, extraction can be carried out according to the target well spacing to achieve the maximum return on investment. When the target well spacing corresponding to the maximum return on investment is greater than the maximum well spacing, extraction can be carried out according to the maximum well spacing to ensure the minimum return on investment for oil and gas extraction and the safety of extraction.

[0141] In practical applications, when deploying injection wells and production wells, any of the following methods can be used to adapt to the mining of target formations of different thicknesses and effectively improve mining efficiency:

[0142] Injection wells and production wells are all vertical wells, and the injection wells and production wells are arranged in a well pattern. Figure 2 As shown, the injection wells and production wells are arranged in a staggered, vertical row. Due to differences in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of different groups can be different, and the well spacing of each group can be obtained using the solution provided above in this application.

[0143] Injection wells and production wells are all vertical wells, and the injection wells and production wells are arranged in a circular well pattern. Figure 3As shown, the injection well and the production well are arranged in a staggered annular well pattern. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of different groups can be different, and the well spacing of each group can be obtained by the above-mentioned scheme provided by the present application.

[0144] The injection well is a horizontal well, the production well is a straight well, and the injection well and the production well are arranged in a staggered annular well pattern. As shown, Figure 4 The injection well is a horizontal well, the production well is a straight well, and the injection well and the production well are arranged in a staggered annular well pattern. As shown,

[0145] The injection well is a horizontal well, the production well is a straight well, and the injection well and the production well are arranged in a staggered annular well pattern. As shown, Figure 5 The injection well is a horizontal well, the production well is a straight well, and the injection well and the production well are arranged in a staggered annular well pattern. As shown,

[0146] The injection well is a horizontal well, the production well is a straight well, and the injection well and the production well are arranged in a staggered annular well pattern. As shown, Figure 6 The injection well is a horizontal well, the production well is a straight well, and the injection well and the production well are arranged in a staggered annular well pattern. As shown,

[0147] The injection well is a horizontal well, the production well is a straight well, and the injection well and the production well are arranged in a staggered annular well pattern. As shown, Figure 7As shown, the production well adopts horizontal well and the injection well adopts straight well staggered well arrangement, the normal line of the midpoint A of the line connecting two adjacent injection wells intersects with the production well at point B, and the distance L of the intersection point B from the injection well is the well spacing of the injection well and the production well finally determined. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of different groups can be different, and the well spacing of each group can be obtained by the scheme provided in the above of the present application. When the target stratum is thick, the production well can adopt longitudinal parallel multi-layer well arrangement.

[0148] The injection well and the production well both adopt horizontal well, and the injection well and the production well are arranged in a row. As shown in the figure, Figure 8 the injection well and the production well both adopt horizontal well parallel row arrangement, and the distance L of the vertical line connecting the production well and the injection well is the well spacing of the injection well and the production well finally determined. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of different groups can be different, and the well spacing of each group can be obtained by the scheme provided in the above of the present application. When the target stratum is thick, the production well and the injection well can adopt longitudinal parallel multi-layer well arrangement.

[0149] The injection well and the production well both adopt horizontal branch well, and the injection well and the production well are staggered. As shown in the figure, Figure 9 the injection well and the production well both adopt horizontal branch well staggered arrangement, and the distance L of the vertical line connecting the production well and the injection well is the well spacing of the injection well and the production well finally determined. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of different groups can be different, and the well spacing of each group can be obtained by the scheme provided in the above of the present application. When the target stratum is thick, the production well and the injection well can adopt longitudinal parallel multi-layer well arrangement.

[0150] The injection well adopts straight well, and the production well adopts horizontal branch well. As shown in the figure, Figure 10 the normal line of the midpoint A of the line connecting two adjacent injection wells intersects with the production well at point B, and the distance L of the intersection point B from the injection well is the well spacing of the injection well and the production well finally determined. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of different groups can be different, and the well spacing of each group can be obtained by the scheme provided in the above of the present application. When the target stratum is thick, the production well can adopt longitudinal parallel multi-layer well arrangement.

[0151] The injection well adopts horizontal branch well, and the production well adopts straight well. As shown in the figure, Figure 11As shown in the figure, the normal line of the midpoint A of the connecting line of two adjacent production wells intersects with the injection well at point B, and the distance L between the intersection point B and the production well is the final determined well spacing between the injection well and the production well. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of each group can be obtained by the scheme provided in the above application. When the target formation is thick, the injection well can adopt the longitudinal parallel multi-layer well arrangement mode.

[0152] As shown in the figure, the normal line of the midpoint A of the connecting line of two adjacent production wells intersects with the injection well at point B, and the distance L between the intersection point B and the production well is the final determined well spacing between the injection well and the production well. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of each group can be obtained by the scheme provided in the above application. When the target formation is thick, the injection well can adopt the longitudinal parallel multi-layer well arrangement mode. Figure 12 As shown in the figure, the normal line of the midpoint A of the connecting line of two adjacent production wells intersects with the injection well at point B, and the distance L between the intersection point B and the production well is the final determined well spacing between the injection well and the production well. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of each group can be obtained by the scheme provided in the above application. When the target formation is thick, the injection well can adopt the longitudinal parallel multi-layer well arrangement mode.

[0153] In practical application, when deploying the injection well and the production well, the injection well can adopt the casing perforation completion mode or the screen completion mode, and the production well can adopt the casing perforation completion mode, the screen completion mode or the open hole completion mode. When injecting the injection fluid into the injection well, the injection fluid volume can be calculated and the injection pressure can be controlled according to the formation permeability of the perforated section, and the sum of the sectional injection volumes in unit time is the injection volume of the injection well in unit time. The sectional injection of the injection fluid flow or the injection pressure can improve the resource production rate and the oil and gas recovery rate.

[0154] More specifically, when the formation permeability of different well sections of the injection well is relatively homogeneous, the casing perforation completion mode or the screen completion mode can be adopted; when the formation permeability of different well sections of the injection well is quite different, the casing perforation completion mode can be adopted, which is convenient for calculating the injection fluid volume and controlling the injection pressure according to the permeability of the perforated section. When calculating the injection fluid volume and controlling the injection pressure according to the permeability of the perforated section, it is generally necessary to ensure that the injection fluid volume of different permeability formations can be within the calculated injection fluid volume range.

[0155] The oil and gas exploitation method provided by the embodiments of the present application will be described below in combination with specific examples, as follows:

[0156] As shown in the figure, the normal line of the midpoint A of the connecting line of two adjacent production wells intersects with the injection well at point B, and the distance L between the intersection point B and the production well is the final determined well spacing between the injection well and the production well. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of each group can be obtained by the scheme provided in the above application. When the target formation is thick, the injection well can adopt the longitudinal parallel multi-layer well arrangement mode. Figure 13 As shown in the figure, the normal line of the midpoint A of the connecting line of two adjacent production wells intersects with the injection well at point B, and the distance L between the intersection point B and the production well is the final determined well spacing between the injection well and the production well. Due to the difference in geological conditions, when there are multiple groups of wells (one injection well and one corresponding production well constitute a group of wells), the well spacing of each group can be obtained by the scheme provided in the above application. When the target formation is thick, the injection well can adopt the longitudinal parallel multi-layer well arrangement mode. Figure 13 Based on the corresponding relationship in the figure, the target starting pressure gradient of the injection fluid can be obtained.

[0157] like Figure 14 The figure shows the relationship between the flow resistance gradient of the injected fluid and the second ratio under different first ratios (abbreviated as permeability / fluid viscosity in the figure). Figure 14 The first ratio can be used to obtain the target trend line of the corresponding relationship between the flow resistance gradient of the injected fluid and the second ratio, and then the target flow resistance gradient of the injected fluid can be determined from the target trend line based on the second ratio. Figure 14 The trend corresponding to the first ratio value that does not have the target formation being evaluated

[0158] When obtaining a trend line, the trend line under the first ratio of the target formation can be obtained according to an interpolation and / or regression fitting method.

[0159] The thickness of the target formation in the study area is 15 m. Both the injection well and the production well are horizontal wells. The length of the oil and gas layer encountered by the horizontal well is 1500 m. The volume coefficient of the target formation fluid is 1.21, the viscosity of the target formation fluid is 1 mPa.s, and the permeability of the target formation is 4×10 -3 μm 2 , the relative permeability of the injected fluid is 0.86, and the viscosity of the injected fluid is 1 mPa.s.

[0160] The formation fracture pressure is 42MPa, the bottom hole pressure of the injection well is 40MPa, the target flow resistance gradient of the injected fluid is 0.6362MPa / d, the target starting pressure gradient of the injected fluid is 3MPa / m, the wellbore radius of the injection well is 0.2m, and the bottom hole fluid pressure of the production well is 3MPa. The pressure difference from the injection well to the bottom hole of the production well is calculated to be 36.4MPa. When the fluid flow rate of the production well is 1m 3 / d (corresponding to the lowest limit of oil and gas production investment return rate), the maximum well spacing between injection wells and production wells is calculated to be 280m using formula (4).

[0161] However, under the condition of maximum well spacing, the amount of fluid injected per unit time by the injection well is small, and the output of the production well is small. In order to achieve effective production, based on the full equivalent barrel oil cost and the production cycle, the flow rate of the output of the production well per unit time is determined to be 38.5m 3 / d (corresponding to the maximum return on investment in oil and gas production), the flow rate of fluid injected into the injection well per unit time is also 38.5m 3 / d, using formula (3) to calculate the well spacing between the injection well and the production well is 200m, 200m is less than 280m, so 200m is the optimal well spacing.

[0162] The oil and gas exploitation method provided by the embodiments of the present application can determine the optimal well spacing between the injection well and the production well, which is of great significance for improving oil and gas recovery and resource production rate, reducing oil and gas exploitation cost, and promoting the development of oil and gas industry scale benefit.

[0163] It should also be noted that the terms "comprising", "containing", or any other variant thereof are intended to cover a non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements, but can also include other elements not expressly listed or inherent to such process, method, article, or apparatus. Without more limitations, an element defined by the phrase "comprising a" does not exclude the existence of additional identical elements in the process, method, article, or apparatus that includes the element.

[0164] The above is only an embodiment of the present application and is not intended to limit the present application. The present application can have various modifications and changes for those skilled in the art. Any modification, equivalent replacement, improvement, etc. within the spirit and principle of the present application shall be included in the scope of claims of the present application.

Claims

1. A method of oil and gas production, c h a r a c t e r i s e d in that, The method comprises the following steps: determining the fracture pressure of the target formation according to a core fracture pressure experiment, and determining the bottom hole pressure of the injection well based on the fracture pressure; determining the flow rate of the injection fluid of the injection well according to the flow rate of the production fluid of the production well; obtaining target data, and calculating the target well spacing between the injection well and the production well based on the target data, wherein the target data comprises the target formation fluid viscosity, the target formation permeability, the target formation fluid volume factor, the relative permeability of the injection fluid, the target threshold pressure gradient of the injection fluid, the target flow resistance gradient of the injection fluid, the wellbore radius of the injection well, the oil and gas layer size of the target formation, and the bottom hole fluid pressure of the production well; deploying the injection well and the production well based on the target well spacing, and carrying out oil and gas production based on the bottom hole pressure of the injection well and the flow rate of the injection fluid of the injection well.

2. The hydrocarbon production method of claim 1, wherein, Before the step of obtaining the target data and calculating the target well spacing between the injection well and the production well based on the target data, the method further comprises the following steps: determining the corresponding relationship between the threshold pressure gradient of the injection fluid and the first ratio according to a core threshold pressure experiment, wherein the first ratio is the ratio of the formation permeability to the injection fluid viscosity; determining the target threshold pressure gradient of the injection fluid based on the corresponding relationship.

3. The hydrocarbon production method of claim 2, wherein, The threshold pressure gradient of the injection fluid is calculated based on the following formula: wherein D is the threshold pressure gradient of the injection fluid, and the unit is MPa / m; ΔP1 is the pressure difference between the fluid pressure at the injection end of the core fluid and the fluid pressure at the discharge end of the core fluid, and the unit is MPa; L1 is the length of the core, and the unit is m.

4. The hydrocarbon production method of claim 1, wherein, Before the step of obtaining the target data and calculating the target well spacing between the injection well and the production well based on the target data, the method further comprises the following steps: determining the corresponding relationship between the flow resistance gradient of the injection fluid and the first ratio according to a fluid flow resistance experiment, wherein the first ratio is the ratio of the formation permeability to the injection fluid viscosity; determining the target flow resistance gradient of the injection fluid based on the corresponding relationship.

5. The hydrocarbon production method of claim 4, wherein, The flow resistance gradient of the injection fluid is calculated based on the following formula: Wherein, E is the flow resistance gradient of the injected fluid, with unit of MPa / d; ΔP2 is the pressure difference between the fluid pressure at the injection end of the core fluid and the fluid pressure at the discharge end of the core fluid, with unit of MPa; Q1 is the flow rate of the fluid discharged at the discharge end of the core fluid per unit time, with unit of m 3 / d; S1 is the cross-sectional area of the core, with unit of m 2 ; L1 is the length of the core, with unit of m.

6. The hydrocarbon production method of claim 1, wherein, determining the fracture pressure of the target formation according to a core fracture pressure experiment comprises the following steps: recording the first time corresponding to the abnormal increase of the flow rate at the discharge end of the core fluid, and taking the pressure at the injection end of the core fluid corresponding to the time closest to the first time as the fracture pressure of the target formation; or, recording the second time corresponding to the abnormal decrease of the pressure at the injection end of the core fluid, and taking the pressure at the injection end of the core fluid corresponding to the time closest to the second time as the fracture pressure of the target formation; or, recording the third time corresponding to the acoustic wave value being higher than the acoustic wave background value, and taking the pressure at the injection end of the core fluid corresponding to the time closest to the third time as the fracture pressure of the target formation.

7. The hydrocarbon production method of claim 1, wherein, The step of determining the bottom hole pressure of the injection well based on the fracture pressure comprises the following steps: controlling the bottom hole pressure of the injection well to be less than the fracture pressure.

8. The hydrocarbon production method of claim 1, wherein, The step of determining the flow rate of the injection fluid of the injection well according to the flow rate of the production fluid of the production well comprises the following steps: controlling the flow rate of the injection fluid of the injection well to be greater than or equal to the flow rate of the production fluid of the production well.

9. The hydrocarbon production method of claim 1, wherein, when the injection well is a vertical well, the hydrocarbon reservoir size of the target formation comprises a thickness of the hydrocarbon reservoir; when the injection well is a directional well, a horizontal well, or a horizontal branch well, the hydrocarbon reservoir size of the target formation comprises a length of the hydrocarbon reservoir.

10. The method of recovering oil and gas according to claim 9, wherein, calculating a target well spacing between the injection well and the production well based on the target data according to the following formula: wherein q is the flow rate of the injection fluid of the injection well in unit time, with the unit of m 3 / d; k is the target formation permeability, with the unit of pm 2 r is the relative permeability of the injection fluid; h is the oil and gas layer thickness or length of the target formation, with the unit of m; P i is the bottom hole pressure of the injection well, with the unit of MPa; P wf is the bottom hole fluid pressure of the production well, with the unit of MPa; Do is the target threshold pressure gradient of the injection fluid, with the unit of MPa / m; r i is the wellbore radius of the injection well, with the unit of m; x is the distance from the center of the injection well, with the unit of m; L is the target well spacing between the injection well and the production well, with the unit of m; Eo is the target flow resistance gradient of the injection fluid, with the unit of MPa / d; p is the viscosity of the target formation fluid, with the unit of mPa.s; B is the volume coefficient of the target formation fluid.​ 11. The hydrocarbon production method of claim 1, wherein, The method further comprises: determining a maximum well spacing between the injection well and the production well.

12. The method of claim 11, wherein, determining the maximum well spacing between the injection well and the production well based on the following formula: Among them, L max is the maximum distance between the injection well and the production well, in meters; P i is the bottom hole pressure of the injection well, in MPa; P wf is the bottom hole fluid pressure of the production well, in MPa; Do is the target starting pressure gradient of the injected fluid, in MPa / m; r i is the wellbore radius of the injection well, in m; h is the oil and gas layer thickness or length of the target formation, in m; q is the flow rate of the injected fluid per unit time of the injection well, in m 3 / d; Eo is the target flow resistance gradient of the injected fluid, in MPa / d.

13. The hydrocarbon production method of claim 11, wherein, determining the maximum well spacing between the injection well and the production well based on the following formula: wherein x is the distance from the center of the injection well, in meters; r i is the wellbore radius of the injection well, in meters; L max is the maximum distance between the injection well and the production well, in meters; h is the oil and gas layer thickness or length of the target formation, in meters; q is the injection fluid flow rate of the injection well per unit time, in meters 3 / d; Eo is the target flow resistance gradient of the injection fluid, in MPa / d; P i is the bottom hole pressure of the injection well, in MPa; P wf is the bottom hole fluid pressure of the production well, in MPa; Do is the target start-up pressure gradient of the injection fluid, in MPa / m.

14. The hydrocarbon production method of claim 1, wherein, the injection well is completed by a casing perforation or a screen completion, and the production well is completed by a casing perforation.

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