CN111257202B - Shale fracturing fluid forced imbibition and flowback experimental method under condition of containing adsorbed gas - Google Patents
Shale fracturing fluid forced imbibition and flowback experimental method under condition of containing adsorbed gas Download PDFInfo
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- 239000012530 fluid Substances 0.000 title claims abstract description 83
- 238000005213 imbibition Methods 0.000 title claims abstract description 38
- 238000002474 experimental method Methods 0.000 title claims abstract description 21
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 claims abstract description 74
- 238000000034 method Methods 0.000 claims abstract description 48
- 239000011148 porous material Substances 0.000 claims abstract description 48
- 230000008569 process Effects 0.000 claims abstract description 23
- 238000003860 storage Methods 0.000 claims abstract description 19
- 239000007789 gas Substances 0.000 claims description 91
- 239000011435 rock Substances 0.000 claims description 82
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 claims description 26
- 230000015572 biosynthetic process Effects 0.000 claims description 21
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 19
- 238000011161 development Methods 0.000 claims description 16
- 238000012544 monitoring process Methods 0.000 claims description 15
- 206010017076 Fracture Diseases 0.000 claims description 14
- 238000004519 manufacturing process Methods 0.000 claims description 14
- 208000010392 Bone Fractures Diseases 0.000 claims description 13
- 230000008859 change Effects 0.000 claims description 13
- 229910052757 nitrogen Inorganic materials 0.000 claims description 13
- 150000001875 compounds Chemical class 0.000 claims description 12
- 230000035699 permeability Effects 0.000 claims description 12
- 238000001179 sorption measurement Methods 0.000 claims description 6
- 238000004364 calculation method Methods 0.000 claims description 5
- 238000011084 recovery Methods 0.000 claims description 5
- 238000012360 testing method Methods 0.000 claims description 4
- 238000010521 absorption reaction Methods 0.000 claims description 3
- 238000012545 processing Methods 0.000 claims description 3
- 239000008398 formation water Substances 0.000 claims description 2
- 238000012216 screening Methods 0.000 claims description 2
- 230000006641 stabilisation Effects 0.000 claims description 2
- 238000011105 stabilization Methods 0.000 claims description 2
- 230000000087 stabilizing effect Effects 0.000 claims description 2
- 239000000126 substance Substances 0.000 claims description 2
- 230000000274 adsorptive effect Effects 0.000 claims 1
- 238000002791 soaking Methods 0.000 abstract description 5
- 230000014759 maintenance of location Effects 0.000 abstract description 3
- 230000006399 behavior Effects 0.000 description 8
- 238000009826 distribution Methods 0.000 description 4
- 230000000694 effects Effects 0.000 description 4
- 238000011065 in-situ storage Methods 0.000 description 4
- 230000000717 retained effect Effects 0.000 description 4
- 238000003795 desorption Methods 0.000 description 3
- 238000009792 diffusion process Methods 0.000 description 3
- 238000010438 heat treatment Methods 0.000 description 3
- 238000004088 simulation Methods 0.000 description 3
- 238000005481 NMR spectroscopy Methods 0.000 description 2
- 239000002734 clay mineral Substances 0.000 description 2
- 238000002591 computed tomography Methods 0.000 description 2
- 230000007547 defect Effects 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- 238000006073 displacement reaction Methods 0.000 description 2
- 238000002347 injection Methods 0.000 description 2
- 239000007924 injection Substances 0.000 description 2
- 239000003345 natural gas Substances 0.000 description 2
- 238000011160 research Methods 0.000 description 2
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- 208000013201 Stress fracture Diseases 0.000 description 1
- 239000000654 additive Substances 0.000 description 1
- 238000009933 burial Methods 0.000 description 1
- 238000012512 characterization method Methods 0.000 description 1
- 238000007796 conventional method Methods 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
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- 230000004048 modification Effects 0.000 description 1
- 239000003209 petroleum derivative Substances 0.000 description 1
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Abstract
本发明公开了一种含吸附气条件下页岩压裂液强制渗吸及返排实验方法，通过将裂缝发育、裂缝欠发育和基块页岩串联构成页岩多尺度储渗空间，将样品放置于长岩心夹持器中，向夹持器中注入甲烷气体，并通过岩心出口端回压阀控制孔隙压力，甲烷吸附平衡后，在岩心进口端正压差作用下实现压裂液强制渗吸，出口端监测压裂液渗吸过程中置换出的甲烷气体，在返排阶段，通过岩心进口端回压阀设置压差模拟压裂液返排过程。过程中实时监测岩心电阻，通过电阻反映压裂液在页岩多尺度储渗空间的渗吸和滞留量。本发明可以真实模拟含吸附气条件下压裂液在页岩多尺度储渗空间的渗吸和返排过程，为页岩气井压裂后优化焖井时间和制定合理的返排制度提供参考。
The invention discloses an experimental method for forced imbibition and flowback of shale fracturing fluid under the condition of containing adsorbed gas. It is placed in the long core holder, and methane gas is injected into the holder, and the pore pressure is controlled by the back pressure valve at the core outlet. , the outlet side monitors the methane gas displaced by the fracturing fluid imbibition process, and in the flowback stage, the pressure difference is set through the back pressure valve at the core inlet end to simulate the fracturing fluid flowback process. During the process, the core resistance is monitored in real time, and the imbibition and retention of fracturing fluid in the multi-scale storage and seepage space of shale is reflected by the resistance. The invention can truly simulate the imbibition and flowback process of the fracturing fluid in the shale multi-scale storage and seepage space under the condition of containing adsorbed gas, and provides a reference for optimizing the soaking time and formulating a reasonable flowback system after fracturing a shale gas well.
Description
Technical Field
The invention relates to the technical field of petroleum and natural gas engineering, in particular to the technical field of shale gas development, and specifically relates to a shale fracturing fluid forced imbibition and flowback experimental method under the condition of containing adsorbed gas.
Background
Shale gas is an important unconventional energy source, and a horizontal well staged hydraulic fracturing technology is one of important means for realizing commercial exploitation of shale gas. Compared with the conventional sandstone and carbonate reservoir, the shale gas reservoir has the characteristics of high clay mineral content, rich organic matters, multi-scale property of page development and pore structure and the like. The shale gas production process comprises diffusion of free gas, seepage and desorption of adsorbed gas, diffusion and seepage. The trapped fracturing fluid has a significant impact on the production of gas. Therefore, the simulation of the seepage and flowback process of the fracturing fluid under the in-situ condition through an indoor experiment has important significance for optimizing the soaking time and reasonably making a flowback system.
The current research on the seepage and flowback of fracturing fluid in rock sample mainly focuses on the following two aspects: the method includes simulating the influence of factors such as in-situ temperature, overburden pressure, positive pressure difference and the like on fluid imbibition behavior. The patent with the application number of CN201810250602.0 provides a rock imbibition amount measuring method under the conditions of simulating the environmental temperature and confining pressure of a rock sample and containing fluid in a gap; the patent with the application number of CN201810226751.3 provides a method for calculating the fluid imbibition amount under a negative pressure state, but the method cannot effectively simulate the influence of overburden pressure and positive pressure difference on imbibition; patent application No. CN201811215010.1 proposes a method of considering the effects of formation stress, formation temperature, fluid injection pressure and page theory on fluid imbibition behavior. Monitoring the shale imbibition process through the physical characteristics of the rock. Patent application No. CN201710526004.7 proposes monitoring the imbibition process of shale by using acoustoelastic properties; the patent with the application number of CN201811581754.5 provides a nuclear magnetic resonance testing device and an experimental method for an online monitoring imbibition experiment. The existing indoor experimental method for shale reservoir fracturing fluid imbibition and flowback mainly has the following two defects: the influence of the shale multi-scale seepage storage space on the seepage behavior of the fracturing fluid cannot be fully considered. The artificial cracks, the natural cracks and the base blocks form a multi-scale methane gas transportation channel. The simulation of the multi-scale seepage storage space of the shale through an indoor experiment has important significance for analyzing the amount of the retained fracturing fluid and the influence of the retained fracturing fluid on the multi-scale gas transportation. Secondly, the influence of the adsorbed gas on the seepage behavior of the fracturing fluid cannot be fully considered. Shale gas occurs in a form including free gas, adsorbed gas and dissolved gas. The proportion of the adsorbed gas in the shale gas is 20-85%, and the seepage and flowback behaviors of the fracturing fluid cannot be accurately described by neglecting the adsorbed gas in the organic matters and clay minerals.
Disclosure of Invention
In order to overcome the defects in the prior art, the invention provides a shale fracturing fluid forced imbibition and flowback experimental method under the condition of containing adsorbed gas. The method comprises the steps of serially connecting a crack development core, a crack under-development core and a base block core to simulate a multi-scale shale storage and seepage space, and putting the simulated shale storage and seepage space into a long core holder. Setting the outlet end back pressure as the reservoir pore pressure, setting the confining pressure as the overburden formation pressure, and heating to the reservoir temperature; vacuumizing the holder for 12 h; injecting methane into the rock sample until the pore pressure reaches the reservoir pressure, and stabilizing for 24 hours; communicating the rock sample with an intermediate container filled with fracturing fluid, wherein the initial pressure of the intermediate container is higher than the pore pressure of the rock sample; the method comprises the steps of reflecting the change of water saturation of a rock sample by monitoring the resistance at two ends of the rock sample, and collecting methane gas displaced in the process of fracturing fluid imbibition at the outlet end of the rock sample by connecting a gas flowmeter; after the resistance of the rock sample is stable, disconnecting the middle container from the rock sample, installing another back pressure valve at the inlet end of the rock sample, wherein the set value of the back pressure is lower than the pore pressure so as to simulate the flowback process, and reflecting the change of water saturation in the flowback process of the fracturing fluid by monitoring the resistance at the two ends of the rock sample; meanwhile, the recovery rate of methane in the rock sample is reflected by monitoring the gas flow. The method comprehensively considers the influence of factors such as shale multi-scale seepage storage space, adsorbed gas, formation temperature, in-situ effective stress, positive pressure difference and the like on the seepage and flowback of the fracturing fluid. The fracturing fluid imbibition and flowback data obtained by the method are real and reliable.
The technical scheme provided by the invention for solving the technical problems is as follows:
a shale fracturing fluid forced imbibition and flowback experimental method under the condition of containing adsorbed gas adopts experimental apparatus including gas source, intermediate container, long core holder, back pressure valve, control valve, pipeline, confining pressure pump, vacuum pump, electric bridge instrument, computer, constant temperature system; the gas source is sequentially connected to the middle container, the long core holder, the back pressure valve and the gas flowmeter through pipelines, the electric bridge instrument is connected to two ends of the long core holder, the confining pressure pump is arranged on the side face of the middle part of the core holder, a four-way pipe is arranged on the pipeline from the middle container to the long core holder, a standard cylinder with methane gas and the back pressure valve are respectively installed on two sides of the four-way pipe, and the back pressure valves are both connected with a back pressure gas source;
the device is adopted for carrying out experiments, and specifically comprises the following steps:
s10, screening and processing the obtained rock sample to prepare a multi-scale seepage storage space containing a fracture development core, a fracture under-developed core and a basal block core which are connected in series to simulate shale, putting the multi-scale seepage storage space into a long core holder, and simulating a formation environment in the core holder through a confining pressure pump and a constant temperature system;
the formation environment comprises confining pressure and temperature, the confining pressure is set overburden formation pressure, and the temperature is set reservoir temperature;
setting back pressure at the inlet end and the outlet end of the long rock core holder, wherein the back pressure value is reservoir pore pressure; vacuumizing the holder; methane is injected into the rock sample until the reservoir pore pressure is reached and stabilized for a period of time.
S20, communicating the rock sample with an intermediate container filled with fracturing fluid, setting the initial pressure of the intermediate container to be higher than the pore pressure of the rock sample, and simulating the seepage process of the fracturing fluid in a shale multi-scale seepage storage space by a pressure attenuation method;
s30, reflecting the change condition of the water content of the shale multi-scale seepage storage space through resistance change by monitoring the resistance at two ends of the rock sample;
meanwhile, methane gas displaced in the process of fracturing fluid imbibition is collected at the outlet end of the rock sample through a gas flowmeter, and the recovery ratio of methane in the rock sample is reflected by monitoring the gas flow.
And step S40, after the resistance of the rock sample is stable, disconnecting the middle container from the rock sample through a valve, opening a control valve of a back pressure valve at the inlet end of the rock sample, setting a back pressure value of the back pressure valve to be lower than the pore pressure of a reservoir, and reflecting the change of water saturation in the process of back-flowing of the fracturing fluid by monitoring the resistance change at two ends of the rock sample.
Further, the fracture development, fracture underdevelopment and base block core identification method in step S10 is to classify according to the grade of gas permeability under 3MPa confining pressure, and the classification standard is as follows: the permeability K is more than 1mD for crack development, the permeability K is less than or equal to 1mD and less than or equal to 0.1mD for crack development, and the permeability K is less than or equal to 0.1mD for basal block. The length of a rock sample which can be placed in the long rock core holder is 15 cm;
vacuumizing the long rock core holder until the vacuum degree reaches more than 0.098MPa, and stopping vacuumizing;
the stabilization time is 24 h;
the amount of methane injected into the rock sample is obtained based on a gas state equation, namely the amount of methane injected is obtained according to the injection amount when the formation pressure is reached.
Further, the outlet end back pressure value set in the step S10 is equal to the reservoir pore pressure;
when the pressure of the pores rises after the adsorbed gas in the pores of the rock sample is replaced by the fracturing fluid and is larger than the set value of the back-pressure valve, the gas enters the gas flowmeter through the back-pressure valve.
Further, the fracturing fluid imbibition process is simulated by a fracturing fluid inlet end pressure attenuation method in the step S20, and the principle is a gas equation of state:
pV＝nRT (1)
in the formula (I), the compound is shown in the specification,
p-pressure of gas, MPa;
v-volume of gas, cm3；
Amount of n-substance, mol;
r-ideal gas constant, dimensionless;
t-thermodynamic temperature, K;
at the same temperature, p1V1＝p2V2，
At p1V1＝p2V2In the formula (I), the compound is shown in the specification,
p1the initial pressure of pressure attenuation, namely the initial pressure of nitrogen contained in the intermediate container, is the rock sample pore pressure at the initial moment plus the positive pressure difference of seepage and absorption of fracturing fluid, namely MPa;
V1is the volume of a standard cylinder of nitrogen, i.e. the initial volume of the intermediate container in cm of nitrogen3；
p2The pressure is the pressure monitored at the inlet end of the rock core in real time, and is MPa;
from this V can be calculated2I.e. core inlet pressure decays to p2The volume of nitrogen contained in the intermediate container;
then through the formula
Then the fracturing fluid permeability of the shale rock sample can be calculatedThe suction amount;
in that
In the formula (I), the compound is shown in the specification,
m-mass of shale rock sample imbibition fracturing fluid, g;
rho-density of fracturing fluid, cm3/g。
Further, the initial value of the positive pressure difference set in step S20 is calculated based on the pressure gradient between the pump stop pressure and the formation pore pressure, and the specific calculation method is as follows:
P＝Δp*l (2)
in the formula (I), the compound is shown in the specification,
p is positive differential pressure, MPa;
delta p is a pressure gradient, MPa/m;
l is the rock sample length, m.
Further, the amount of fluid in the pore space is reflected according to the resistance of the rock sample in step S30, and the principle is based on the algi formula.
In the formula
I is the resistivity increase coefficient and is dimensionless;
Rw-formation water resistivity, Ω · m;
Sw-water saturation, decimal;
Rt-resistivity of the water-bearing rock, Ω · m;
b-lithology coefficient, dimensionless;
n-saturation index, dimensionless.
Further, in step S40, the inlet-end back pressure is lower than the reservoir pressure, the inlet-end back pressure set value is determined according to the production pressure difference, and the specific calculation method is as follows:
pback pressure＝pPore pressure-ΔpProduction of*l (4)
In the formula (I), the compound is shown in the specification,
pback pressureInlet end back pressure, MPa;
ppore pressurePore pressure, MPa;
Δpproduction ofThe pressure gradient of the bottom of the well in the actual production process is MPa/m;
l is the length of the core, m.
The invention has the following advantages:
(1) the invention relates to a multi-scale storage and permeation space formed by connecting shale samples in series based on permeability grades from high to low, which more truly reflects the pore structure of shale under the formation condition. The advantages of connecting a plurality of shale samples in series are mainly embodied in the following two aspects: firstly, in the production process of a shale gas well, a shale base block, a natural fracture and an artificial fracture network form a gas multi-scale transport channel. The shale gas production process comprises desorption of adsorbed gas in the matrix, diffusion and slip flow in natural microfractures and darcy flow in large scale artificial fractures. The seepage and suction behaviors of the fracturing fluid in each channel cannot be accurately divided by adopting a single rock sample; and the three shale samples are connected in series, so that the adsorption quantity of methane gas is increased, the methane displacement effect of the imbibition fracturing fluid on the samples is more obvious, the methane flow at the outlet end is convenient to measure, and the experiment precision is improved.
(2) The back pressure valves arranged at the outlet end and the inlet end of the long rock core holder can respectively simulate the formation pore pressure and the flowback pressure difference, and further simulate the seepage and flowback of the fracturing fluid in the shale under the condition of containing adsorbed gas. The shale reservoir containing the adsorption gas is unique in property compared with other conventional natural gas reservoirs, and the important characteristic is often ignored by previous researchers in the process of researching the seepage and absorption of the fracturing fluid. The reason for this is that two experimental conditions of pore pressure and positive pressure difference cannot be satisfied at the same time. The invention creatively arranges back-pressure valves at the inlet end and the outlet end of the core holder. The set value of the outlet end back pressure valve is the pore pressure, when the pore pressure of the rock sample is larger than the set value, the back pressure valve automatically discharges gas, the original set value is maintained, and the back pressure valve does not influence the positive pressure difference applied by the inlet end. The inlet end back pressure valve is connected with the core holder when the flowback is started, and the back pressure value is smaller than the pore pressure, so that the flowback process of the fracturing fluid under reservoir conditions can be truly simulated, and the simulation of the flowback behavior of the fracturing fluid under various pressure differences can be realized.
(3) In the conventional method for reflecting the water content of the rock sample in the research, a holder is usually placed in a nuclear magnetic resonance instrument and a CT (computed tomography) scanner, the two methods can reflect the water content and the distribution characteristics of the water content in the rock sample, but the problems that the monitoring cost is high in the process of long-time seepage and flowback, and the additives in the fracturing fluid can interfere the experimental result, so that the accurate experimental result cannot be obtained. The electric bridge instrument can economically and efficiently measure the resistance of the rock sample in the process of fracturing fluid imbibition and flowback, and reflect the change of water saturation in the rock sample in real time.
Drawings
FIG. 1 is a flow chart of a shale fracturing fluid forced imbibition and flowback experimental method under the condition of containing adsorbed gas according to the invention;
FIG. 2 is a schematic diagram of a device for a shale fracturing fluid forced imbibition and flowback experiment under a condition of containing adsorbed gas;
fig. 3 is a schematic diagram of fracture development, underdevelopment, and the cascading of shale in a long core holder.
In the figure:
1-a nitrogen source; 2-fracturing fluid; 3, a constant temperature system; 4. 13, 32-pressure sensor; 5-a methane standard cylinder; 6. 11, 19, 25, 26, 27, 28, 29-control valve; 7-pipeline; 8, heating wires; 9-tandem rock sample; 10-long core holder; 12. 20, 30-pressure gauge; 14-wire, 15-computer; 16. 22-a back pressure valve; 17. 23-back pressure air source; 18-confining pressure pump; 21-a vacuum pump; 24-bridge instrument; 31-high precision gas flow meter; 33-fracturing fluid sample cylinder; 34-standard cylinder of nitrogen.
Detailed Description
The present invention will be further described with reference to the following examples and the accompanying drawings.
As shown in fig. 1, the experimental device adopted in the method for the experiment of forced seepage and flowback of shale fracturing fluid under the condition of gas adsorption comprises a gas source, an intermediate container, a long core holder 10, back pressure valves (16, 22), control valves (6, 11, 19, 25, 26, 27, 28, 29), a pipeline 7, a confining pressure pump 18, a vacuum pump 21, an electric bridge instrument 24, a computer 15 and a constant temperature system 3; the gas source is a nitrogen source 1, the gas source is sequentially connected to a middle container, a long core holder 10, a back pressure valve and a gas flowmeter 31 through pipelines, an electric bridge instrument 24 is connected to two ends of the long core holder 10, a confining pressure pump 18 is arranged on the side face of the middle of the long core holder 10, a four-way pipe is arranged on the pipeline from the middle container to the long core holder 10, a standard cylinder 5 with methane gas and a back pressure valve 16 are respectively installed on two sides of the four-way pipe, the back pressure valves (16 and 22) are both connected with back pressure gas sources (17 and 23), a fracturing fluid sample cylinder 33 and a nitrogen standard cylinder 34 are separated through a piston, and fracturing fluid 2 is placed inside the fracturing fluid sample cylinder 34;
the specific implementation method adopting the device comprises the following steps:
s10, processing and forming a shale sample with the burial depth of 2810m taken from a certain block of the Sichuan basin, and measuring basic physical properties of the shale sample, wherein the recommended size is a columnar body with the diameter of 25mm and the length of 50mm (the size contains enough standard characterization unit bodies with pore structures, and meanwhile, the capillary end effect can be eliminated). The formation temperature is set to be 80 ℃, the overlying formation pressure is set to be 75MPa, the pore pressure is set to be 30MPa, and the production pressure difference is set to be 3 MPa. Samples were classified according to permeability grade from high to low into fracture development, fracture underdevelopment and basal block samples, with the criteria shown in table 1. And each grade sample is connected in series to form a shale multi-scale storage and seepage space. The whole system is heated to the reservoir temperature of 80 ℃ by the constant temperature system 3 and the heating wire 8. After the temperature of the system is stable, the confining pressure is increased to 75 MPa. And after the confining pressure is stable, vacuumizing the system for 24 hours by using a vacuum pump 21. Injecting methane gas into the rock core holder through a methane standard cylinder 5, gradually increasing the pore pressure to reach the formation pore pressure of 30MPa, enabling methane to reach adsorption balance in the shale sample, and closing a valve 25; at the moment, the pressure of the inlet end back pressure valve and the pressure of the outlet end back pressure valve are both the formation pore pressure of 30 MPa.
TABLE 1 permeability K versus pore structure
S20, pressurizing the fracturing fluid 2 in the intermediate container and the pipeline through a nitrogen source 1, adding a positive pressure difference of 3MPa, and monitoring the rock sample resistance in real time through an electric bridge instrument 24. The water content in the sample was obtained based on the Archie's formula. The specific calculation formula is as follows:
in the formula (I), the compound is shown in the specification,
Swthe water saturation of the rock core is decimal;
b is a wettability index, is dimensionless, has a value related to lithology, and is selected from the prior art according to experimental requirements, wherein the value is 1;
Rtthe real-time resistivity of the rock sample monitored by the bridge instrument is omega m;
R0resistivity at 100% water in the rock sample, Ω · m; n is a saturation index and is dimensionless, the n value is used for correcting the nonuniformity of saturation micro-distribution, the more nonuniform the saturation micro-distribution is, the larger the n value is, and the value is 2;
and S30, when the methane adsorbed in the shale pores is replaced, the pore pressure is greater than the set back pressure value, and the outlet end gas flowmeter records the amount of the methane replaced after imbibition.
Based on the formula:
in the formula (I), the compound is shown in the specification,
eta is the recovery ratio of methane displaced by the fracturing fluid,%;
Vm2displacement of methane in cm for the outlet end3/g；
Vm1Is the amount of adsorbed gas and free gas in the shale, cm3/g。
S40, when the resistance of the rock sample is stable, closing the valve 26, and setting the pressure difference according to the production pressure difference of 3MPaThe pressure of the back pressure valve is 27MPa, the control valve 27 of the back pressure valve is opened, and the change of the water saturation is reflected by monitoring the resistance at the two ends of the rock sample. The pressure attenuation curve of the pore pressure of the pressure rock sample in the flowback process can be obtained through the pressure sensor 32, and then the seepage capability of the rock sample is evaluated. The test result shows that the amount of methane entering the shale multi-scale seepage-storing space through the methane standard cylinder 5 is 0.80cm3G, amount of methane displaced at the outlet end was 0.35cm3The ultimate methane recovery was therefore 43.75%.
The principle of the method is as follows: samples with different crack development degrees are connected in series to simulate a shale multi-scale storage and seepage space, and the shale samples in the holder are subjected to methane adsorption balance and then fracturing fluid seepage under the pressure condition. The characteristic of the change of the resistance of the rock sample with time reflects the seepage and retention conditions of the fracturing fluid in the shale multi-scale seepage storage space and the influence of the seepage and retention conditions on the multi-scale transport capacity of methane gas.
According to the invention, the seepage and flowback conditions of the fracturing fluid under in-situ conditions (including formation temperature, overburden pressure, pore pressure, adsorbed gas, positive differential pressure and the like) are truly simulated. The water content of the shale is reflected through the resistivity characteristics of the sample, and the influence of the retained fracturing fluid on the desorption of the adsorbed gas can be obtained through a flowmeter at the outlet end. Provides a theoretical basis for reasonably formulating a flowback system for optimizing the soaking time. Based on the above experimental results, the optimal soaking time of the well is 20 days, and is longer than that obtained by using a single sample, which indicates that the time required for the distribution of the retained fracturing fluid to be stable under the actual formation conditions is longer. If the shale fracturing fluid imbibition and flowback behaviors are simulated by the prior art, the obtained time is shorter than the actually required time, so that the soaking effect is not optimal.
Although the present invention has been described with reference to the above embodiments, it should be understood that the present invention is not limited to the above embodiments, and those skilled in the art can make various changes and modifications without departing from the scope of the present invention.
Claims (7)
1. A shale fracturing fluid forced imbibition and flowback experimental method under the condition of containing adsorbed gas is characterized in that an adopted experimental device comprises a gas source, an intermediate container, a long rock core holder, a back pressure valve, a control valve, a pipeline, a confining pressure pump, a vacuum pump, an electric bridge instrument, a computer and a constant temperature system; the gas source is sequentially connected to the middle container, the long core holder, the back pressure valve and the gas flowmeter through pipelines, the electric bridge instrument is connected to two ends of the long core holder, the confining pressure pump is arranged on the side face of the middle part of the core holder, a four-way pipe is arranged on the pipeline from the middle container to the long core holder, a standard cylinder with methane gas and the back pressure valve are respectively arranged on two sides of the four-way pipe, and the back pressure valves are both connected with a back pressure gas source;
the device is adopted for carrying out experiments, and specifically comprises the following steps:
s10, screening and processing the obtained rock sample to prepare a multi-scale seepage storage space containing a fracture development core, a fracture under-developed core and a basal block core which are connected in series to simulate shale, putting the multi-scale seepage storage space into a long core holder, and simulating a formation environment in the core holder through a confining pressure pump and a constant temperature system;
the formation environment comprises confining pressure and temperature, the confining pressure is set overburden formation pressure, and the temperature is set reservoir temperature;
setting back pressure at the inlet end and the outlet end of the long rock core holder, wherein the back pressure value is reservoir pore pressure; vacuumizing the holder; injecting methane into the rock sample until reaching reservoir pore pressure, and stabilizing for a period of time;
s20, communicating the rock sample with an intermediate container filled with fracturing fluid, setting the initial pressure of the intermediate container to be higher than the pore pressure of the rock sample, and simulating the seepage process of the fracturing fluid in a shale multi-scale seepage storage space by a pressure attenuation method;
s30, reflecting the change condition of the water content of the shale multi-scale seepage storage space through resistance change by monitoring the resistance at two ends of the rock sample;
meanwhile, methane gas displaced in the process of fracturing fluid imbibition is collected at the outlet end of the rock sample through a gas flowmeter, and the recovery ratio of methane in the rock sample is reflected by monitoring the gas flow;
and step S40, after the resistance of the rock sample is stable, disconnecting the middle container from the rock sample through a valve, opening a control valve of a back pressure valve at the inlet end of the rock sample, setting a back pressure value of the back pressure valve to be lower than the pore pressure of a reservoir, and reflecting the change of water saturation in the process of back-flowing of the fracturing fluid by monitoring the resistance change at two ends of the rock sample.
2. The method for the shale fracturing fluid forced imbibition and flowback experiment under the condition of gas adsorption as claimed in claim 1, wherein the identification method of the fracture development core, the fracture under-development core and the basal block core in the step S10 is classified according to the grade of gas permeability under 3MPa confining pressure, and the classification standard is as follows: the permeability K is more than 1mD and is crack development, the permeability K is less than or equal to 1mD and is less than crack development, and the permeability K is less than or equal to 0.1mD and is a base block; the length of a rock sample which can be placed in the long rock core holder is 15 cm;
vacuumizing the long rock core holder until the vacuum degree reaches more than 0.098MPa, and stopping vacuumizing;
the stabilization time is 24 h;
the amount of methane injected into the rock sample is obtained based on a gas state equation.
3. The method for the experiment of forced imbibition and flowback of the shale fracturing fluid under the condition of containing the adsorptive gas as claimed in claim 2, wherein the outlet end back pressure value set in the step S10 is equal to the reservoir pore pressure;
when the pressure of the pores rises after the adsorbed gas in the pores of the rock sample is replaced by the fracturing fluid and is larger than the set value of the back-pressure valve, the gas enters the gas flowmeter through the back-pressure valve.
4. The method for shale fracturing fluid forced imbibition and flowback test under the condition of containing adsorbed gas as claimed in claim 1, wherein said step S20 simulates the fracturing fluid imbibition process through a fracturing fluid inlet end pressure decay method, and the principle is a gas equation of state:
PV＝nRT (1)
in the formula (I), the compound is shown in the specification,
p-pressure of gas, MPa;
v-volume of gas, cm3；
Amount of n-substance, mol;
r-ideal gas constant, dimensionless;
t-thermodynamic temperature, K;
at the same temperature, p1V1＝p2V2，
At p1V1＝p2V2In the formula (I), the compound is shown in the specification,
p1the initial pressure of pressure attenuation, namely the initial pressure of nitrogen contained in the intermediate container, is the rock sample pore pressure at the initial moment plus the positive pressure difference of seepage and absorption of fracturing fluid, namely MPa;
V1is the volume of a standard cylinder of nitrogen, i.e. the initial volume of the intermediate container in cm of nitrogen3；
p2The pressure is the pressure monitored at the inlet end of the rock core in real time, and is MPa;
from this V can be calculated2I.e. core inlet pressure decays to p2The volume of nitrogen contained in the intermediate container;
then through the formula
Calculating the seepage capacity of the fracturing fluid of the shale rock sample;
in that
In the formula (I), the compound is shown in the specification,
m-mass of shale rock sample imbibition fracturing fluid, g;
rho-density of fracturing fluid, cm3/g。
5. The method for shale fracturing fluid forced imbibition and flowback test under the condition of adsorbed gas according to claim 4, wherein the initial value of the positive pressure difference set in the step S20 is calculated based on the pressure gradient between the pump-stopping pressure after fracturing and the formation pore pressure, and the specific calculation method is as follows:
P＝Δp*l (2)
in the formula (I), the compound is shown in the specification,
p is positive differential pressure, MPa;
delta p is a pressure gradient, MPa/m;
l is the rock sample length, m.
6. The method for the experiment of forced imbibition and flowback of the shale fracturing fluid under the condition of containing the adsorbed gas as claimed in claim 1, wherein the amount of the fluid in the pores is reflected according to the resistance of the rock sample in the step S30, and the principle is based on the algic formula:
in the formula
I is the resistivity increase coefficient and is dimensionless;
Rw-formation water resistivity, Ω · m;
Sw-water saturation, decimal;
Rt-resistivity of the water-bearing rock, Ω · m;
b-lithology coefficient, dimensionless;
n-saturation index, dimensionless.
7. The method as claimed in claim 1, wherein in step S40, the inlet-end back pressure is lower than the reservoir pressure, the inlet-end back pressure setting value is determined according to the production pressure difference, and the specific calculation method is as follows:
pback pressure＝pPore pressure-ΔpProduction of*l (4)
In the formula (I), the compound is shown in the specification,
pback pressureInlet end back pressure, MPa;
ppore pressurePore pressure, MPa;
Δpproduction ofThe pressure gradient of the bottom of the well in the actual production process is MPa/m;
l is the length of the core, m.
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