Method and device for determining well blocking time based on true triaxial pre-CO2 post-pressure salinity

Abstract

The present invention discloses a method and device for determining the well-clogging time based on the salinity after true triaxial pre-CO2 pressure, which belongs to the technical field of shale gas extraction, wherein the method includes establishing the total salinity change of field return fluid under dimensionless time based on dimensionless time, drawing the field return total salinity-dimensionless time change curve, and determining the first well-clogging time; drawing the CO2 concentration-dimensionless time change curve according to field tests, and determining the second well-clogging time; based on the total salinity change of field return fluid under dimensionless time, obtaining the diffusion salinity change under dimensionless time, drawing the diffusion salinity-dimensionless time change curve; based on the diffusion salinity-dimensionless time change curve, obtaining the degree of shale fracture development, determining the shale fracture development characteristics, and determining the first well-clogging time or the second well-clogging time as the optimal well-clogging time. The present invention obtains accurate well-clogging time by analyzing the shape and inflection point of the curve, thereby increasing the extraction of shale gas.

Description

Technical Field

[0001] The present invention relates to the technical field of shale gas exploitation, and in particular to a method for producing shale gas based on a true triaxial pre-co 2 Method and device for determining well blocking time by post-pressure salinity. Background Art

[0002] China has abundant shale oil resources, and industrial oil flows of varying degrees have been found in multiple basins, including the Songliao Basin, Bohai Bay Basin, Ordos Basin, and Junggar Basin. my country's shale oil is mainly deposited in continental lake phases, and often has the characteristics of poor reservoir properties, low overall maturity, strong heterogeneity, and high wax content. Large-scale volume fracturing is required to improve near-well permeability and increase single-well production. Currently, shale oil wells that have been built and produced generally face the problem of rapid production decline and low primary recovery. It has been proposed at home and abroad to use supercritical CO before volume fracturing. 2 As a pre-energized plug injected into shale formations, it can not only improve the effect of rock breaking and fracture formation, but also replenish formation energy and improve the properties of shale and crude oil. It has gradually developed into a "pre-CO2 injection" that integrates fracturing, energy replenishment, upgrading and production. 2 Energy-enhanced pressure-driven technology". The study found that CO 2 Sparkling water with CO 2 and water properties, which can significantly improve the micro-nano pore sweep range, oil washing effect and CO 2 However, the pre-CO 2 , CO 2 Bubble water composite fracturing technology is only in the field test stage, and there is a lack of in-depth understanding of the mechanism of increased production. The microscopic oil displacement mechanism after fracturing is still unclear, and there is no unified conclusion on the applicability of well blocking, well blocking time and subsequent drainage methods.

[0003] At present, the calculation methods of the well-clogging time of shale oil and gas wells are mainly developed based on the field fracturing fluid return rate and indoor permeability test. Some scholars have also proposed methods to calculate the well-clogging time based on the well-clogging pressure decay characteristics and reservoir numerical simulation. However, the current methods are mainly developed based on the traditional slickwater volume fracturing technology. For the continental shale oil reservoir with highly developed laminae, CO pre- 2 , CO 2 There is no report on the calculation method of well blocking time for bubble water composite fracturing at home and abroad. 2 The water-shale interaction causes acid corrosion and salt ion dissolution, which significantly increases the salinity of the retained fracturing fluid. During the shale oil well drainage stage, the fracturing fluid in the primary fractures, secondary fractures, and tertiary fractures is discharged step by step, and the salinity in fractures of different levels varies greatly. The change in the salt concentration curve of the produced fluid can be used as a basis for optimizing the well blocking time.

[0004] Therefore, how to provide a method and device to optimize the well blocking time according to the change of the salt concentration curve of the produced liquid is a technical problem that needs to be solved urgently by those skilled in the art. Summary of the invention

[0005] To this end, the present invention provides a true three-axis front CO 2 The invention discloses a method and device for determining the well blocking time by the post-pressure salinity, so as to solve the existing technical problems.

[0006] In order to achieve the above object, the present invention provides the following technical solutions:

[0007] According to a first aspect of the present invention, a true three-axis front CO 2 The method of determining the well blocking time based on post-pressure salinity includes:

[0008] Step S1: Select a laminar shale sample, place the laminar shale sample in a true triaxial experimental device, simulate the experimental environment, analyze and sort out the flowback fluid data in the laminar shale sample, and obtain the total salinity change of the flowback fluid of the laminar shale sample under the flowback time;

[0009] Step S2: obtaining fracture surface salinity based on the total salinity change of the flowback fluid of the laminar shale sample under the flowback time;

[0010] Step S3: based on the fracture surface salinity of the laminar shale sample, predict the total salinity change of the field flowback fluid under the flowback time;

[0011] Step S4: Based on the total salinity change of the field flowback fluid at the flowback time, a dimensionless similarity relationship is established to obtain the dimensionless time;

[0012] Step S5: based on the dimensionless time, establish the total salinity change of the field flowback fluid under the dimensionless time, draw the change curve of the field flowback total salinity-dimensionless time, and determine the first well blocking time;

[0013] Step S6: Mapping CO based on field tests 2 The concentration-dimensionless time variation curve is used to determine the second well blocking time;

[0014] Step S7: based on the total salinity change of the field flowback fluid under dimensionless time, obtain the diffusion salinity change under dimensionless time, and draw a diffusion salinity-dimensionless time change curve;

[0015] Step S8: Based on the variation curve of diffusion salinity-dimensionless time, the degree of shale fracture development is obtained, the characteristics of shale fracture development are determined, and the first well blocking time or the second well blocking time is determined as the optimal well blocking time.

[0016] Furthermore, in step S5, the total salinity change of the field flowback fluid under dimensionless time is obtained by a first formula, wherein the first formula is:

[0017] ;

[0018] Where C is the total salinity of the on-site flowback, A is the exposed area, and C 0 is the fracture surface salinity, M is the mass of injected fracturing fluid, t D is the dimensionless time, and n is the degree of shale fracture development.

[0019] Furthermore, in step S7, the diffusion salinity change of the field return fluid under dimensionless time is obtained by a second formula, wherein the second formula is:

[0020] ;

[0021] Among them, t D is dimensionless time, n is the degree of shale fracture development, C D is the diffuse salinity.

[0022] Furthermore, in step S8, the degree of shale fracture development is obtained by a third formula, wherein the third formula is:

[0023] ;

[0024] Among them, n is the degree of shale fracture development, C D is the diffusion salinity, t is the flowback time, and Δt is the flowback time variable.

[0025] Further, if the shale fracture development degree meets the first condition, the shale fracture development characteristic is judged to be a simple main fracture, and the optimal well blocking time is the first well blocking time; if the shale fracture development degree meets the second condition, the shale fracture development characteristic is judged to be a simple main fracture penetrating the laminar fracture, and the optimal well blocking time is the maximum value of the first well blocking time and the second well blocking time; if the shale fracture development degree meets the third condition, the shale fracture development characteristic is judged to be a simple main fracture penetrating the laminar fracture and the induced fracture, and the optimal well blocking time is the minimum value of the first well blocking time and the second well blocking time; if the shale fracture development degree meets the fourth condition, the shale fracture development characteristic is judged to be a complex main fracture penetrating the laminar fracture, and the optimal well blocking time is the second well blocking time.

[0026] Furthermore, the first condition is that the degree of development n of the shale fractures is single; the second condition is that the degree of development n of the shale fractures is a finite number, and the degree of development n of the shale fractures in the initial stage is less than 0.5; the third condition is that the degree of development n of the shale fractures is a finite number, and the degree of development n of the shale fractures in the initial stage is greater than 0.5; the fourth condition is that the degree of development n of the shale fractures is infinite.

[0027] According to a second aspect of the present invention, a true three-axis front CO 2 A device for determining the well blocking time based on the post-pressure salinity, used to implement any of the above-mentioned true triaxial pre-CO 2 The method of determining the well blocking time based on post-pressure salinity includes:

[0028] The pumping module is used to pump crude oil and CO into the fractures of laminar shale samples. 2 Sparkling water;

[0029] True triaxial loading module, used to apply or unload loads to laminar shale samples, simulating and adjusting the pressure environment of laminar shale samples;

[0030] A sample fixing module, arranged on the true triaxial loading module, wherein the true triaxial loading module applies or unloads load to the laminar shale sample through the sample fixing module;

[0031] A temperature control module, provided on the true triaxial loading module, is used to heat the laminar shale sample and simulate and adjust the temperature environment of the laminar shale sample;

[0032] A monitoring module for obtaining flowback fluid parameters in laminar shale samples;

[0033] A processing module is used to measure the fluid quality of the return fluid in the laminar shale sample.

[0034] Furthermore, the true triaxial loading module includes a bottom fixed structure, a top surface fixed structure, a side base, a vertical pressure plate, a horizontal pressure plate and a hydraulic telescopic rod. The bottom fixed structure is fixed on the device, and the top surface fixed structure is fixed above the bottom fixed structure. Side bases are provided on both sides of the device, and a vertical pressure plate is provided on the inner side of the side base. A hydraulic telescopic rod is provided between the side base and the vertical pressure plate. Horizontal pressure plates are provided on the inner sides of the top surface fixed structure and the bottom fixed structure, and the horizontal pressure plate is connected to the top surface fixed structure through a hydraulic telescopic rod. Liquid injection / exhaust holes are opened on the vertical pressure plate.

[0035] Furthermore, the sample fixing module includes a plurality of heat-resistant and corrosion-resistant rubber plates, and the heat-resistant and corrosion-resistant rubber plates are arranged on the inner side surfaces of the vertical pressing plate and the horizontal pressing plate.

[0036] The present invention has the following advantages:

[0037] The present invention selects a laminar shale sample, places the laminar shale sample in a true triaxial experimental device, simulates the experimental environment, analyzes and organizes the flowback fluid data in the laminar shale sample, obtains the total salinity change of the flowback fluid of the laminar shale sample under the flowback time; obtains the fracture surface salinity based on the total salinity change of the flowback fluid of the laminar shale sample under the flowback time; predicts the total salinity change of the field flowback fluid under the flowback time based on the fracture surface salinity of the laminar shale sample; establishes a dimensionless similarity relationship based on the total salinity change of the field flowback fluid under the flowback time, and obtains the dimensionless time; establishes the total salinity change of the field flowback fluid under the dimensionless time based on the dimensionless time, draws the change curve of the field flowback total salinity-dimensionless time, and determines the first well blocking time; draws the CO2-CO ... 2 The concentration-dimensionless time change curve is used to determine the second well blocking time; based on the total salinity change of the field return fluid under dimensionless time, the diffusion salinity change under dimensionless time is obtained, and the diffusion salinity-dimensionless time change curve is drawn; based on the diffusion salinity-dimensionless time change curve, the shale fracture development degree is obtained, the shale fracture development characteristics are determined, and the first well blocking time or the second well blocking time is determined as the optimal well blocking time. The present invention obtains accurate well blocking time by analyzing the shape and inflection point of the curve, thereby increasing the production of shale gas.

[0038] The present invention builds a true triaxial laminar shale flowback physical simulation device with different complex artificial fracture forms to determine the surface salinity of the in-situ fracture section of the laminar shale and the diffusion rate of salt ions in the matrix pores. Combined with the dimensionless salinity curve of the return fluid tested on site, the shape and inflection point of the curve are used to analyze the pre-CO 2 and CO 2 The present invention is to clarify the fracture morphology formed by bubble water fracturing and calculate the optimal well blocking time. 2 - Reservoir interaction, CO 2 - The degree of improvement of the diffusion and displacement characteristics of hydrocarbon fluids on the efficiency of imbibition oil recovery, and the exploration of the CO front in shale oil reservoirs 2 and CO 2 The method of efficient drainage and production increase after bubble water pressure is of great significance to accelerating the economic and efficient development of continental shale oil in my country. BRIEF DESCRIPTION OF THE DRAWINGS

[0039] In order to more clearly illustrate the implementation methods of the present invention or the technical solutions in the prior art, the following briefly introduces the drawings required for the implementation methods or the description of the prior art. Obviously, the drawings in the following description are only exemplary, and for ordinary technicians in this field, other implementation drawings can be derived from the provided drawings without creative work.

[0040] The structures, proportions, sizes, etc. illustrated in this specification are only used to match the contents disclosed in the specification so as to facilitate understanding and reading by persons familiar with the technology. They are not used to limit the conditions under which the present invention can be implemented, and therefore have no substantial technical significance. Any structural modification, change in proportion or adjustment of size shall still fall within the scope of the technical contents disclosed in the present invention without affecting the effects and purposes that can be achieved by the present invention.

[0041] Figure 1 A schematic diagram of the structure of the device provided in Example 1 of the present invention;

[0042] Figure 2 The total salinity / CO of the on-site flowback provided in Example 2 of the present invention 2 Concentration-dimensionless time variation curve;

[0043] Figure 3 A variation curve of diffusion salinity-dimensionless time for shale fracture development degree satisfying the first condition provided in Example 2 of the present invention;

[0044] Figure 4 A variation curve of diffusion salinity-dimensionless time for shale fracture development degree satisfying the second condition provided in Example 2 of the present invention;

[0045] Figure 5 A variation curve of diffusion salinity-dimensionless time for shale fracture development degree satisfying the third condition provided in Example 2 of the present invention;

[0046] Figure 6 A variation curve of diffusion salinity-dimensionless time for shale fracture development degree satisfying the fourth condition provided in Example 2 of the present invention;

[0047] Figure 7 A shale fracture development characteristic diagram provided in Example 2 of the present invention, wherein the shale fracture development degree meets the first condition;

[0048] Figure 8 A shale fracture development characteristic diagram of the shale fracture development degree satisfying the second condition provided in Example 2 of the present invention;

[0049] Fig. 9 A shale fracture development characteristic diagram of the shale fracture development degree satisfying the third condition provided in Example 2 of the present invention;

[0050] Fig.10 A shale fracture development characteristic diagram of the shale fracture development degree satisfying the fourth condition provided in Example 2 of the present invention;

[0051] In the figure:

[0052] 1 pump injection module; 2 true triaxial loading module; 3 sample fixing module; 4 processing module; 201 bottom fixing structure; 202 top surface fixing structure; 203 side base; 204 vertical pressing plate; 205 horizontal pressing plate; 206 hydraulic telescopic rod; 207 injection / exhaust liquid hole. DETAILED DESCRIPTION

[0053] The following is a description of the implementation of the present invention by specific embodiments. People familiar with the art can easily understand other advantages and effects of the present invention from the contents disclosed in this specification. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0054] Example 1

[0055] Based on true three-axis front CO 2 A device for determining the time of well blocking by post-pressure salinity, such as Figure 1 As shown, including:

[0056] Pumping module 1 is used to pump crude oil and CO into the fractures of laminar shale samples. 2 Sparkling water;

[0057] True triaxial loading module 2, used to apply or unload loads to laminar shale samples, and simulate and adjust the pressure environment of laminar shale samples;

[0058] The sample fixing module 3 is arranged on the true triaxial loading module 2, and the true triaxial loading module 2 applies or unloads load to the laminar shale sample through the sample fixing module 3;

[0059] The temperature control module is provided on the true triaxial loading module 2 and is used to heat the laminar shale sample and simulate and adjust the temperature environment of the laminar shale sample;

[0060] A monitoring module for obtaining flowback fluid parameters in laminar shale samples;

[0061] The processing module 4 is used to measure the fluid quality of the return fluid in the laminar shale sample.

[0062] The true triaxial loading module 2 includes a bottom fixed structure 201, a top surface fixed structure 202, a side base 203, a vertical pressure plate 204, a horizontal pressure plate 205 and a hydraulic telescopic rod 206. The bottom fixed structure 201 is fixed on the device, and the top surface fixed structure 202 is fixed above the bottom fixed structure 201. Side bases 203 are provided on both sides of the device, and a vertical pressure plate 204 is provided on the inner side of the side base 203. A hydraulic telescopic rod 206 is provided between the side base 203 and the vertical pressure plate 204. Horizontal pressure plates 205 are provided on the inner sides of the top surface fixed structure 202 and the bottom fixed structure 201. The horizontal pressure plate 205 is connected to the top surface fixed structure 202 through the hydraulic telescopic rod 206, and a liquid injection / exhaust hole 207 is opened on the vertical pressure plate 204. Specifically, the hydraulic telescopic rod 206 drives the vertical pressure plate 204 to extend or contract to apply or unload the load. The hydraulic telescopic rod 206 also drives the horizontal pressure plate 205 in the top fixed structure to apply or unload the load, thereby applying comprehensive pressure to the laminated shale sample.

[0063] The sample fixing module 3 includes a plurality of heat-resistant and corrosion-resistant rubber plates, which are arranged on the inner side of the vertical pressing plate 204 and the horizontal pressing plate 205. Specifically, the bottom heat-resistant and corrosion-resistant rubber plate, the top heat-resistant and corrosion-resistant rubber plate, and the side heat-resistant and corrosion-resistant rubber plate are connected to the inner side of the bottom fixing structure 201 by strong glue. Similarly, the corrosion rubber plate is connected to the inner side of the top surface fixing structure 202, and the side heat-resistant and corrosion-resistant rubber plate is connected to the inner side of the vertical pressing plate 204. The bottom heat-resistant and corrosion-resistant rubber plate, the top heat-resistant and corrosion-resistant rubber plate, and the side heat-resistant and corrosion-resistant rubber plate all play a role in protecting the sample and sealing.

[0064] The pump injection module 1 includes a gas cylinder, a controllable temperature and pressure reactor, a metering pump and a switch. The gas cylinder is provided with a pressure reducing valve, the outlet of the pressure reducing valve is connected to the switch, and the switch is connected to the injection / exhaust liquid hole 207 on the vertical pressing plate 204 through a stainless steel pressure-resistant pipeline. The controllable temperature and pressure reactor has a piston, and a heating pipe is provided in its wall to heat the liquid in the reactor. The metering pump is connected to the injection port at the bottom of the controllable temperature and pressure reactor through a stainless steel pressure-resistant pipeline, and the controllable temperature and pressure reactor is connected to the injection / exhaust liquid hole 207 on the vertical pressing plate 204 through a stainless steel pressure-resistant pipeline. Specifically, the metering pump is used to pump the liquid into the bottom of the controllable temperature and pressure reactor, and the piston is pushed to pump the CO 2 Bubble water is pressed into true triaxial loading module 2.

[0065] The temperature control module includes a temperature control chip, a heating device, and a temperature sensor. The heating device is built into the bottom fixed structure 201, the top fixed structure 202, and the vertical pressure plate 204. The temperature sensors are respectively located on the inner side of the vertical pressure plate 204 and between the bottom fixed structures 201. The real-time measured data is used by the temperature control chip to control the heating device to heat up or stop working.

[0066] The monitoring module includes a salinity sensor, a conductivity sensor, and a pressure sensor. The salinity sensor, the conductivity sensor, and the pressure sensor are respectively located between the bottom fixed structure 201 to monitor the salinity, conductivity, and fluid pressure of the area. The pressure sensor is built into the top fixed structure 202 and the vertical pressure plate 204 to monitor the triaxial pressure.

[0067] The post-processing module 4 includes a hand pump, a back pressure valve, a fluid comprehensive measuring instrument, a beaker, and a balance. The liquid inlet end of the back pressure valve is connected to any hole of the injection / exhaust liquid hole 207 through a high-pressure stainless steel pipeline, the back pressure hole is connected to the hand pump through a high-pressure stainless steel pipeline, and the liquid outlet is connected to the fluid comprehensive measuring instrument through a high-pressure stainless steel pipeline. Then the fluid flows into the beaker on the balance to measure its mass.

[0068] The use process of Example 1 of the present invention is as follows:

[0069] 40 / 60 mesh quartz sand was laid at the artificial cracks of the oil-saturated sample to support the cracks, and the sample was placed in the bottom fixed structure 201 of the true triaxial loading module 2. The horizontal pressing plate 205 was pressed downward by the background control until the sensor detected a pressure of 5N. The rubber sheet was checked to be tightly closed, and the vertical pressing plate 204 was further closed by the background with a pressure of 5N. The sample was preloaded with a triaxial stress of 2MPa and a back pressure of 1MPa.

[0070] The 1.5MPa metering pump at the inlet pumps crude oil until the back pressure valve drips crude oil. The back pressure, injection pressure and triaxial stress are increased simultaneously, and the temperature control module is turned on to restore the temperature and pressure environment of the sample to the original formation environment, including overburden stress, maximum horizontal ground stress, minimum horizontal ground stress, pore pressure and temperature.

[0071] During the temperature and pressure loading process, due to the adjustment of internal stress in the laminar shale, the external triaxial stress and pore pressure need to be adjusted in real time. The in-situ environment is maintained unchanged for 24 hours.

[0072] A certain amount of supercritical CO is pumped into the injection port 2 After the slug is plugged, close the valve and inject a certain amount of CO 2 Nanobubble water segment plug. After the pumping is completed, all valves are closed, the well is simulated to be blocked for 24 hours, and the temperature and pressure changes are monitored in real time.

[0073] Open the inlet valve to allow the fluid to flow out at a constant flow rate, and use the flow meter and conductivity to measure the solution volume and salinity changes in real time. According to the output fluid salinity analysis test, the multiple groups of output fluid data obtained are analyzed and sorted.

[0074] Example 2

[0075] Based on true three-axis front CO2 The method of determining the well blocking time based on post-pressure salinity includes:

[0076] Step S1: Select laminar shale samples, process them into 4 pieces according to the requirements, place them in a true triaxial experimental device, simulate the experimental environment, analyze and sort out the return fluid data in the laminar shale samples, and fit the formula according to the change of salinity curve: , obtain the total salinity change of the flowback fluid of the laminar shale sample under the flowback time;

[0077] Step S2: obtaining fracture surface salinity based on the total salinity change of the flowback fluid of the laminar shale sample under the flowback time;

[0078] Step S3: based on the fracture surface salinity of the laminar shale sample, predict the total salinity change of the field flowback fluid under the flowback time;

[0079] The formula for the total salinity change of laminar shale sample flowback fluid under flowback time is:

[0080] C = AC 0 M + 2 π rNAC 0 M [ 2 k ( P c + P π ) t ( μ w k rw + μ o k ro ) ϕ ( S wf − S wi ) ] n ;

[0081] Where C is the total salinity of the on-site flowback, A is the exposed area, and C 0 is the fracture surface salinity, M is the mass of the injected fracturing fluid, r is the average pore radius of shale, N is the number of capillaries per unit cross-sectional area, k is the absolute permeability of shale, is the capillary pressure, is the clay osmotic pressure, t is the flowback time, and are the viscosities of oil and water, respectively, and are the relative permeabilities of gas and water, and are the front water saturation and initial water saturation respectively, and n is the degree of shale fracture development.

[0082] Step S4: Salinity C is a dimensionless quantity, so the right side of the equation is dimensionless. In order to generalize the indoor experimental results to the field data analysis, it is necessary to establish a dimensionless similarity relationship. Based on the total salinity change of the field return fluid under the return time, a dimensionless similarity relationship is established to obtain the dimensionless time;

[0083] The dimensionless time is:

[0084] ;

[0085] Step S5: based on the dimensionless time, establish the total salinity change of the field flowback fluid under the dimensionless time, draw the change curve of the field flowback total salinity-dimensionless time, and determine the first well blocking time;

[0086] Therefore, the total salinity change of the field return fluid under dimensionless time is obtained by the first formula, where the first formula is:

[0087] ;

[0088] Where C is the total salinity of the on-site flowback, A is the exposed area, and C 0 is the fracture surface salinity, M is the mass of injected fracturing fluid, t D is the dimensionless time, and n is the degree of shale fracture development.

[0089] Step S6: Mapping CO based on field tests 2 The concentration-dimensionless time variation curve is used to determine the second well blocking time;

[0090] Step S7: based on the total salinity change of the field flowback fluid under dimensionless time, obtain the diffusion salinity change under dimensionless time, and draw a diffusion salinity-dimensionless time change curve;

[0091] The dimensionless total salinity C is composed of the dimensionless diffusion salinity and the dimensionless convective salinity. Taking the logarithm of both sides of the first formula, we get the second formula.

[0092] The diffusion salinity change of the field return fluid under dimensionless time is obtained by the second formula, where the second formula is:

[0093] ;

[0094] in, , C is the total salinity of the on-site flowback, A is the exposed area, C 0 is the fracture surface salinity, M is the mass of injected fracturing fluid, t D is dimensionless time, n is the degree of shale fracture development, C D is the diffuse salinity.

[0095] Step S8: Based on the variation curve of diffusion salinity-dimensionless time, the degree of shale fracture development is obtained, the characteristics of shale fracture development are determined, and the first well blocking time or the second well blocking time is determined as the optimal well blocking time.

[0096] The segmented characteristics of the curve corresponding to the change curve of diffusion salinity-dimensionless time are used to evaluate the pre-CO 2 The fracture morphology after fracturing, where the curve slope n reflects the fracture development formed by on-site fracturing. The third formula for calculating the slope is as follows:

[0097] ;

[0098] Where n is the degree of shale fracture development, C Dis the diffusion salinity, t is the flowback time, and Δt is the flowback time variable.

[0099] like Figure 2 As shown, the total salinity C / CO is plotted 2 Concentration as a function of dimensionless time t D The variation curve of total salinity C with dimensionless time t D The time when the precipitation salinity on the change curve is stable is the first well blocking time T1, and the CO 2 Concentration as a function of dimensionless time t D The change curve of CO 2 The time when the concentration rises sharply is the second well blocking time T2. According to the degree of development of shale fractures, the optimal well blocking time is selected between the first well blocking time T1 and the second well blocking time T2.

[0100] like Figure 3-6 As shown, the total salinity C and CO at different times according to the field test 2 Concentration, plot C D and dimensionless time t D The change curve shows that with the increase of production time, the salt ion content in the produced fluid shows a rapid increase, gradual slowdown, and then flattening change process. By analyzing multiple groups of small square data, multiple groups of reflux salt time curves are obtained, and the curves can be segmented according to the rising turning points of the curves. The interaction between artificial fractures and activated laminae is determined according to the curve segmentation and slope, which is used as an indicator of the degree of fracture development. The salt ion concentration change curve has the characteristics of "rapid response in the initial stage and obvious change stage". Therefore, the slope n of the curve can be used as a reference coefficient for its well-clogging optimization time to improve the rationality of the well-clogging time.

[0101] Because the curve is segmented, the curve may have multiple slopes n. Therefore, the shale fracture development degree n in the initial stage is defined as n1, the shale fracture development degree n in the next stage is defined as n2, and so on.

[0102] like Figure 3 and 7 As shown in the figure, the degree of shale fracture development meets the first condition, which is that the degree of shale fracture development n is single and n1≈0.5. This indicates that the main fracture is simple and the exposed area of ​​the fracture is not large. 2 The effect is not strong, and the influence of T2 does not need to be considered. The shale fracture development characteristics are judged to be simple main fractures, and the optimal well blocking time is the first well blocking time T1.

[0103] like Figure 4 and 8As shown, the degree of shale fracture development satisfies the second condition. The second condition is that the degree of shale fracture development n is a finite number, and n1 < 0.5, n2 > 0.5, 0 < n3 < n2. This indicates the development of multi-scale fractures, and the fluid is easy to enter and exit, with a large exposed area of fractures. At this time, it is necessary to ensure the first shut-in time T1 for fluid dissolution and CO 2 The second shut-in time T2 for the action is long enough to ensure sufficient rock-fluid reaction. Then, it is determined that the shale fracture development feature is that the simple main fracture penetrates the laminated fracture, and the optimal shut-in time is the maximum value of the first shut-in time T1 and the second shut-in time T2.

[0104] As Figure 5 and 9 As shown, the degree of shale fracture development satisfies the third condition. The third condition is that the degree of shale fracture development n is a finite number, and n1 > 0.5, n2 < 0.5, 0 < n3 < n2. This indicates the development of multi-scale fractures, and the fluid is easy to enter but difficult to discharge. At this time, only a moderate shut-in time is required, and the salt ion diffusion and CO 2 Only one reaction needs to be in place. Return the fluid early to create a channel for later oil and gas, so as to avoid a large amount of liquid staying and being difficult to discharge, which affects the oil and gas production. Then, it is determined that the shale fracture development feature is that the simple main fracture penetrates the laminated fracture and induced fractures, and the optimal shut-in time is the minimum value of the first shut-in time T1 and the second shut-in time T2.

[0105] As Figure 6 and 10 As shown, the degree of shale fracture development satisfies the fourth condition. The fourth condition is that the degree of shale fracture development n is an infinite number, and n1 < 0.5, n2 < n1 < 0.5. It is determined that the shale fracture development feature is that the complex main fracture penetrates the laminated fracture, and the effect of salt ions is not strong, so the influence of T1 does not need to be considered, and the optimal shut-in time is the second shut-in time T2.

[0106] Although the present invention has been described in detail with general descriptions and specific embodiments above, based on the present invention, some modifications or improvements can be made, which are obvious to those skilled in the art. Therefore, these modifications or improvements made without departing from the spirit of the present invention all fall within the scope of the present invention claimed.

Claims

1. A method for determining the well blocking time based on the salinity after true triaxial pre-CO2 pressure, characterized in that: include: Step S1: Select a laminar shale sample, place the laminar shale sample in a true triaxial experimental device, simulate the experimental environment, analyze and sort out the flowback fluid data in the laminar shale sample, and obtain the total salinity change of the flowback fluid of the laminar shale sample under the flowback time; Step S2: obtaining fracture surface salinity based on the total salinity change of the flowback fluid of the laminar shale sample under the flowback time; Step S3: based on the fracture surface salinity of the laminar shale sample, predict the total salinity change of the field flowback fluid under the flowback time; Step S4: Based on the total salinity change of the field flowback fluid at the flowback time, a dimensionless similarity relationship is established to obtain the dimensionless time; Step S5: based on the dimensionless time, establish the total salinity change of the field flowback fluid under the dimensionless time, draw the change curve of the field flowback total salinity-dimensionless time, and determine the first well blocking time; Step S6: Draw a change curve of CO2 concentration-dimensionless time according to the field test to determine the second well blocking time; Step S7: based on the total salinity change of the field flowback fluid under dimensionless time, obtain the diffusion salinity change under dimensionless time, and draw a diffusion salinity-dimensionless time change curve; Step S8: based on the variation curve of diffusion salinity-dimensionless time, the degree of shale fracture development is obtained, the characteristics of shale fracture development are determined, and the first well-clogging time or the second well-clogging time is determined as the optimal well-clogging time; In step S5, the total salinity change of the field flowback fluid under dimensionless time is obtained by a first formula, wherein the first formula is: ； Where C is the total salinity of the on-site flowback, A is the exposed area, C0 is the salinity of the fracture surface, M is the mass of the injected fracturing fluid, and t D is the dimensionless time, n is the degree of shale fracture development; In step S7, the diffusion salinity change of the field return fluid under dimensionless time is obtained by the second formula, wherein the second formula is: ； Among them, t D is dimensionless time, n is the degree of shale fracture development, C D for diffuse salinity; In step S8, the degree of shale fracture development is obtained by a third formula, wherein the third formula is: ； Among them, n is the degree of shale fracture development, C D is the diffusion salinity, t is the flowback time, and Δt is the flowback time variable.

2. The method for determining the well blocking time based on the salinity after true triaxial pre-CO2 pressure as claimed in claim 1 is characterized in that: If the shale fracture development degree meets the first condition, the shale fracture development characteristic is judged to be a simple main fracture, and the optimal well blocking time is the first well blocking time; if the shale fracture development degree meets the second condition, the shale fracture development characteristic is judged to be a simple main fracture penetrating a laminar fracture, and the optimal well blocking time is the maximum value of the first well blocking time and the second well blocking time; if the shale fracture development degree meets the third condition, the shale fracture development characteristic is judged to be a simple main fracture penetrating a laminar fracture and an induced fracture, and the optimal well blocking time is the minimum value of the first well blocking time and the second well blocking time; if the shale fracture development degree meets the fourth condition, the shale fracture development characteristic is judged to be a complex main fracture penetrating a laminar fracture, and the optimal well blocking time is the second well blocking time; The first condition is that the degree of development n of the shale fractures is single; the second condition is that the degree of development n of the shale fractures is finite, and the degree of development n of the shale fractures in the initial stage is less than 0.5; the third condition is that the degree of development n of the shale fractures is finite, and the degree of development n of the shale fractures in the initial stage is greater than 0.5; the fourth condition is that the degree of development n of the shale fractures is infinite.

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