CN116066049B - Shale gas well fracturing crack area calculation method based on liquid phase ion characterization - Google Patents
Shale gas well fracturing crack area calculation method based on liquid phase ion characterization Download PDFInfo
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- 238000004364 calculation method Methods 0.000 title claims abstract description 31
- 238000012512 characterization method Methods 0.000 title claims abstract description 13
- 239000007791 liquid phase Substances 0.000 title claims abstract description 11
- 150000002500 ions Chemical class 0.000 claims abstract description 97
- 239000012530 fluid Substances 0.000 claims abstract description 72
- 238000000034 method Methods 0.000 claims abstract description 54
- 230000008859 change Effects 0.000 claims abstract description 27
- 238000002791 soaking Methods 0.000 claims abstract description 24
- 239000007788 liquid Substances 0.000 claims abstract description 17
- 230000008569 process Effects 0.000 claims abstract description 14
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- 238000002156 mixing Methods 0.000 claims abstract description 6
- 238000012216 screening Methods 0.000 claims abstract 2
- 239000002245 particle Substances 0.000 claims description 72
- 238000005259 measurement Methods 0.000 claims description 25
- 238000003825 pressing Methods 0.000 claims description 13
- 230000033558 biomineral tissue development Effects 0.000 claims description 10
- 238000004458 analytical method Methods 0.000 claims description 6
- 238000007873 sieving Methods 0.000 claims description 3
- 230000000737 periodic effect Effects 0.000 claims description 2
- 230000000475 sunscreen effect Effects 0.000 claims 1
- 239000000516 sunscreening agent Substances 0.000 claims 1
- 238000010276 construction Methods 0.000 abstract description 5
- 238000011161 development Methods 0.000 abstract description 5
- 239000007789 gas Substances 0.000 description 26
- 150000003839 salts Chemical class 0.000 description 10
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 description 9
- 230000000694 effects Effects 0.000 description 8
- 238000012986 modification Methods 0.000 description 7
- 230000004048 modification Effects 0.000 description 7
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- 238000002474 experimental method Methods 0.000 description 5
- 238000011160 research Methods 0.000 description 5
- 230000018109 developmental process Effects 0.000 description 4
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 4
- 239000011435 rock Substances 0.000 description 4
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 4
- 239000004215 Carbon black (E152) Substances 0.000 description 3
- 238000009530 blood pressure measurement Methods 0.000 description 3
- 229930195733 hydrocarbon Natural products 0.000 description 3
- 150000002430 hydrocarbons Chemical class 0.000 description 3
- 238000005342 ion exchange Methods 0.000 description 3
- 230000009466 transformation Effects 0.000 description 3
- 239000008367 deionised water Substances 0.000 description 2
- 229910021641 deionized water Inorganic materials 0.000 description 2
- 238000010586 diagram Methods 0.000 description 2
- LFEUVBZXUFMACD-UHFFFAOYSA-H lead(2+);trioxido(oxo)-$l^{5}-arsane Chemical compound [Pb+2].[Pb+2].[Pb+2].[O-][As]([O-])([O-])=O.[O-][As]([O-])([O-])=O LFEUVBZXUFMACD-UHFFFAOYSA-H 0.000 description 2
- 239000011159 matrix material Substances 0.000 description 2
- 238000012544 monitoring process Methods 0.000 description 2
- 239000003345 natural gas Substances 0.000 description 2
- 239000012071 phase Substances 0.000 description 2
- 239000011148 porous material Substances 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- BHPQYMZQTOCNFJ-UHFFFAOYSA-N Calcium cation Chemical compound [Ca+2] BHPQYMZQTOCNFJ-UHFFFAOYSA-N 0.000 description 1
- KRHYYFGTRYWZRS-UHFFFAOYSA-M Fluoride anion Chemical compound [F-] KRHYYFGTRYWZRS-UHFFFAOYSA-M 0.000 description 1
- JLVVSXFLKOJNIY-UHFFFAOYSA-N Magnesium ion Chemical compound [Mg+2] JLVVSXFLKOJNIY-UHFFFAOYSA-N 0.000 description 1
- NPYPAHLBTDXSSS-UHFFFAOYSA-N Potassium ion Chemical compound [K+] NPYPAHLBTDXSSS-UHFFFAOYSA-N 0.000 description 1
- FKNQFGJONOIPTF-UHFFFAOYSA-N Sodium cation Chemical compound [Na+] FKNQFGJONOIPTF-UHFFFAOYSA-N 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 239000008346 aqueous phase Substances 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 230000009286 beneficial effect Effects 0.000 description 1
- 229910001424 calcium ion Inorganic materials 0.000 description 1
- 238000002425 crystallisation Methods 0.000 description 1
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- 230000001419 dependent effect Effects 0.000 description 1
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- 238000009826 distribution Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000008398 formation water Substances 0.000 description 1
- 229910001425 magnesium ion Inorganic materials 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
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- YPJKMVATUPSWOH-UHFFFAOYSA-N nitrooxidanyl Chemical compound [O][N+]([O-])=O YPJKMVATUPSWOH-UHFFFAOYSA-N 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 239000003209 petroleum derivative Substances 0.000 description 1
- 229910001414 potassium ion Inorganic materials 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000002407 reforming Methods 0.000 description 1
- 229910001415 sodium ion Inorganic materials 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/25—Methods for stimulating production
- E21B43/26—Methods for stimulating production by forming crevices or fractures
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- G06—COMPUTING; CALCULATING OR COUNTING
- G06F—ELECTRIC DIGITAL DATA PROCESSING
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Abstract
The invention provides a shale gas well fracturing fracture area calculating method based on liquid phase ion characterization, which comprises the following steps: screening shale scraps and drying to obtain shale samples; (2) Mixing the shale sample obtained in the step (1) with a simulated fracturing fluid to obtain a soaking fluid; (3) Periodically analyzing the ion content change of each ion in the soaking liquid obtained in the step (2), and determining key ions; (4) And (3) calculating the specific surface area and the fracture surface area of the well fracture system according to the concentration of the key ions obtained in the step (3). The calculation method is simple, the operation is simple, no additional mine construction process flow and equipment are needed, the indoor and mine construction are easy to realize, the cost can be greatly saved, and the method has a wide application prospect along with the development of shale.
Description
Technical Field
The invention belongs to the field of oil and gas development of petroleum and natural gas engineering, relates to a method for calculating the fracturing fracture area of a shale gas well, and particularly relates to a method for calculating the fracturing fracture area of the shale gas well based on liquid phase ion characterization.
Background
The fracturing transformation technology is a main technical means for shale gas reservoir development at present. Experience in field development shows that the fracturing modification effect of the shale gas well is a main factor influencing the productivity of the shale gas well besides the nature of the shale gas reservoir. Therefore, the method for evaluating the fracturing modification effect of the shale gas well has a very important role in determining the productivity of the shale gas well.
In the prior art, a microseism monitoring technology is generally adopted to evaluate the fracturing modification effect of the shale gas well, namely, the acquired microseism signals are processed and interpreted through the acquisition of the microseism signals, the acquired fracture parameter information is obtained, and the fracturing modification effect of the shale gas well is evaluated by utilizing the fracture parameter information.
The microseism monitoring can reliably detect the position and the density of the cracks generated by hydraulic fracturing, and effectively evaluate the fracturing transformation effect, but the technology has the advantages of complex field implementation process and program, long time consumption and extremely high cost. In view of the fundamental aim of hydraulic fracturing, the method is to increase the fracture density and the drainage area of a reservoir, calculate the total area of a fracture system formed by hydraulic fracturing modification, and can be used as an effective means for evaluating the hydraulic fracturing effect.
Shale gas reservoirs belong to hydrocarbon source rock gas reservoirs, and reservoirs are fine-grained sedimentary clastic rock and are quiet water sedimentary and reduction environment products. In the hydrocarbon generation process of shale gas reservoirs, a large amount of primary formation water migrates away from the reservoir with the liquid carrying action of the hydrocarbon generation and drainage process, resulting in crystallization of a large amount of soluble salts in the reservoir pores as the aqueous phase evaporates. When contacted with an external aqueous fluid, the soluble salts of the nodules in the pores re-dissolve in the water, resulting in a rapid increase in the mineralization of the aqueous solution.
In 2013, zhang Xiaoyu proposed a page-building HF-1 well fracturing and flowback effect analysis, which was performed using engineering parameters (see page-building HF-1 well fracturing and flowback effect analysis, zhang Xiaoyu, natural gas technology and economy, volume 7, phase 1, pages 40-42).
In 2017, talbot et al put forward a fracturing fluid flowback characterization method of artificial crack complexity and application, wherein the method is based on the fact that an ion exchange phenomenon exists between a reservoir matrix and fracturing fluid, a representation method of salt concentration difference in flowback fluid is analyzed, a saturation distribution mathematical model of salt concentration in flowback fluid after volume transformation is established, and salt concentration and crack complexity characteristic relations in different flowback fluids are analyzed (see "fracturing fluid flowback characterization method of artificial crack complexity and application", talbot et al, petroleum drilling and production technology, volume 39, phase 1 and pages 20-24).
In 2019, wang Liang and the like propose research and application of ion content change of fracturing fluid after shale fracturing of Changning zone, the method is based on ion exchange phenomenon existing between reservoir matrix and fracturing fluid, analyzes the relation between ion change and well-stewing time and productivity in the flowback process after fracturing, and provides a basis for optimizing the well-stewing time to a certain extent (see research and application of ion content change of fracturing fluid after shale fracturing of Changning zone, wang Liang and the like, oilfield chemistry, volume 45, 5 th, pages 99-102).
CN 106978997a discloses a method for calculating the fracture area of a shale gas well based on a soluble salt content test, which utilizes the phenomenon that the mineralization degree of the fracturing fluid is increased due to the dissolution of soluble salt in a shale reservoir in the fracturing fluid, tests the soluble salt content of shale in unit area under the condition of simulating the reservoir through a shale soaking experiment of deionized water, calculates the total soluble salt content of the well fracturing fluid dissolved in the hydraulic fracturing fracture by combining the change of the mineralization degree of the fracturing fluid before and after the hydraulic fracturing of the shale gas well, and calculates the fracture area of a hydraulic fracturing reforming fracture network by the conservation of the mass of the soluble salt.
The four methods all consider the change of the ion content in the liquid discharge in the research process, but do not consider that the contact area of the shale reservoir and the fracturing fluid and the mineralization degree of the fracturing fluid can influence the change of the ion content in the flowback fluid.
In the prior art, in the research of the total area of a fracture system formed by hydraulic fracturing modification, considered factors are incomplete, and research results have certain defects. Therefore, it has become one of the urgent problems in the art to provide a method for researching the total area of the fracture system formed by hydraulic fracturing modification in consideration of more influencing factors.
Disclosure of Invention
The invention aims to provide a calculation method for the fracturing fracture area of a shale gas well based on liquid phase ion characterization, which is characterized in that firstly, the variation rule of shale with the same mass and different surface areas soaked in fracturing fluid is analyzed in an indoor experiment mode, and the variation rule of the ion content of shale with different specific surface areas in the fracturing fluid is calculated. And then the surface area of the crack is calculated by detecting the ion change condition after pressure measurement on site.
In order to achieve the aim of the invention, the invention adopts the following technical scheme:
the invention provides a shale gas well fracturing fracture area calculating method based on liquid phase ion characterization, which comprises the following steps:
(1) Sieving shale scraps and drying to obtain shale samples;
(2) Mixing the shale sample obtained in the step (1) with a simulated fracturing fluid to obtain a soaking fluid;
(3) Periodically analyzing the ion content change of each ion in the soaking liquid obtained in the step (2), and determining key ions;
(4) And (3) calculating the specific surface area and the fracture surface area of the well fracture system according to the concentration of the key ions obtained in the step (3).
According to the calculation method provided by the invention, firstly, the change rule of the shale with the same mass and different surface areas soaked in the fracturing fluid is analyzed in an indoor experiment mode, and the change rule of the ion content of the shale with different specific surface areas in the fracturing fluid is calculated. And then the surface area of the crack is calculated by detecting the ion change condition after pressure measurement on site.
The calculation method is simple, the operation is simple, no additional mine site construction process flow and equipment are required to be added, the indoor and mine sites are easy to realize, and the cost can be greatly saved.
The simulated fracturing fluid in the step (2) is prepared by deionized water according to the ion content in the fracturing fluid, and the main ions and the content of the simulated fracturing fluid comprise: the content of chlorine ion is 5000-30000mg/L, the content of fluorine ion is 0-20mg/L, the content of nitrate radical is 50-200mg/L, the content of sulfate radical is 50-1000mg/L, the content of sodium ion is 1000-10000mg/L, the content of potassium ion is 100-500mg/L, the content of magnesium ion is 100-500mg/L, the content of calcium ion is 500-2000mg/L.
Preferably, the shale samples of step (1) include large particle shale samples, medium particle shale samples, small particle shale samples, and small particle shale samples.
Preferably, the large particle shale sample has an average particle size of 400-500 μm, such as 400 μm, 410 μm, 420 μm, 430 μm, 440 μm, 450 μm, 460 μm, 470 μm, 480 μm, 490 μm or 500 μm, but is not limited to the recited values, and other non-recited values within the range of values are equally applicable.
Preferably, the mean particle size of the medium-particle shale sample is 200-250 μm, which may be, for example, 200 μm, 210 μm, 220 μm, 230 μm, 240 μm or 250 μm, but is not limited to the recited values, as other non-recited values within the range of values are equally applicable.
Preferably, the small particle shale samples have an average particle size of 150-200 μm, which may be, for example, 150 μm, 160 μm, 170 μm, 180 μm, 190 μm or 200 μm, but are not limited to the recited values, and other non-recited values within the range of values are equally applicable.
Preferably, the average particle size of the fine particulate shale sample is 50-100 μm, for example, 50 μm, 60 μm, 70 μm, 80 μm, 90 μm or 100 μm, but is not limited to the recited values, and other non-recited values within the range of values are equally applicable.
According to the invention, the variation of ion concentration of shale soaked in the fracturing fluid is simulated by adopting shale samples with different average particle sizes, and the ion exchange of shale soaked in the fracturing fluid in a certain time under the same reservoir condition is mainly dependent on the contact area of the shale and the fracturing fluid. The smaller the particle size of a pile of shale particles of the same mass, the larger the surface area and the faster the ion content changes after contact with the fracturing fluid. Therefore, in the development of shale soaking experiments with different particle sizes, the surface area of the fracture after fracturing is calculated by utilizing the change relation between the specific surface areas of the shale with different particle sizes and the ion content of the fracturing fluid.
Preferably, the mesh number of the screen used in the step (1) is 50-250 mesh, for example, 50 mesh, 80 mesh, 100 mesh, 150 mesh, 200 mesh or 250 mesh, but not limited to the recited values, and other non-recited values in the range of values are equally applicable.
Preferably, the temperature of the drying in the step (1) is 60-80 ℃, for example, 60 ℃, 65 ℃, 70 ℃, 75 ℃ or 80 ℃, but the method is not limited to the listed values, and other non-listed values in the numerical range are applicable.
Preferably, the drying time in the step (1) is more than or equal to 24 hours, for example, 24 hours, 25 hours, 26 hours, 27 hours or 28 hours, but the method is not limited to the listed values, and other non-listed values in the range of values are equally applicable.
Preferably, the end point of the drying of step (1) is a shale sample constant weight.
Preferably, the mass ratio of the shale sample to the simulated fracturing fluid in the step (2) is 1 (3-6), for example, 1:3, 1:3.5, 1:4, 1:4.5, 1:5, 1:5.5 or 1:6, but not limited to the recited values, and other non-recited values in the range of values are equally applicable.
Preferably, the mineralization degree of the simulated fracturing fluid in the step (2) is 13000-18000mg/L, and can be 13000mg/L, 14000mg/L, 15000mg/L, 16000mg/L, 17000mg/L or 18000mg/L, for example, but not limited to the recited values, and other non-recited values in the numerical range are equally applicable.
Preferably, the periodic analysis of step (3) is: and (3) repeatedly measuring the ion content of each ion in the soaking liquid obtained in the step (2).
Preferably, the time interval for the repeated measurements is 3-6 days, which may be, for example, 3 days, 4 days, 5 days or 6 days.
Preferably, the endpoint of the repeated measurement is: the absolute difference epsilon of key ions in the adjacent two measurement results is less than or equal to 0.1, wherein the calculation formula of the absolute difference epsilon is as follows:
wherein a is the concentration of key ions obtained by the first measurement in the two adjacent measurement processes; b is the concentration of the key ions obtained by the second measurement in the adjacent two measurement processes.
Preferably, the key ions in the step (3) are ions with the largest ion concentration fluctuation range in the soaking solution.
Preferably, step (4) the specific surface area S of the well fracture system Ratio of The calculation formula of (2) is as follows:
S ratio of ＝αe βCi
Wherein alpha is a first coefficient, beta is a second coefficient, e is a natural logarithm, and Ci is the ion concentration of key ions in the fracturing fluid.
Preferably, the alpha and beta are calculated by adopting a data fitting method through the specific surface area of the shale sample and the key ion concentration in the soaking liquid obtained in the step (2).
According to the invention, a plurality of groups of specific surface area and ion content change data are obtained through experiments on alpha and beta. By S Ratio of ＝αe βCi The formula brings the specific surface and the key ion data into the formula, and the first coefficient alpha and the second coefficient beta are obtained through calculation by combining a data fitting method.
Preferably, the calculation formula S of the specific surface area of the shale sample Page ratio The method comprises the following steps:
wherein S is Page(s) For the surface area of shale sample, m Pressing To simulate the quality of fracturing fluid.
Preferably, the shale sample has a surface area S Page(s) The calculation formula of (2) is as follows:
wherein V is Page(s) And d is the average particle size of the shale sample.
Preferably, the volume V of the shale sample Page(s) The calculation formula of (2) is as follows:
wherein m is Page(s) For the mass of shale sample ρ Page(s) Is the density of the shale sample.
The density rho of the shale sample Page(s) The method is calculated by a drainage method, and comprises the following specific steps: the mass of the shale is weighed and the shale is processed,
preferably, the fracture surface area S of step (4) Watch (watch) The calculation formula of (2) is as follows:
S watch (watch) ＝S Ratio of ×V Pressing ×ρ Pressing
Wherein V is Pressing Is the volume of fracturing fluid in a shale gas well, ρ Pressing Is the density of the fracturing fluid.
Preferably, the volume V of the fracturing fluid in the rock gas well Pressing The calculation formula of (2) is as follows:
V pressing ＝V Into (I) -V Return
Wherein V is Into (I) For the amount of fracturing fluid entering the well, V Return The fracturing fluid is returned after the fracturing.
As a preferable technical scheme of the invention, the method for calculating the fracturing fracture area of the shale gas well based on liquid phase ion characterization comprises the following steps:
(1) The shale scraps are screened by a 50-250 mesh sieve and then dried for more than 24 hours at the temperature of 60-80 ℃ until the weight of the shale sample is constant, so that a large-particle shale sample, a medium-particle shale sample, a small-particle shale sample and a small-particle shale sample are obtained; the average particle size of the large-particle shale sample is 400-500 mu m, the average particle size of the medium-particle shale sample is 200-250 mu m, the average particle size of the small-particle shale sample is 150-200 mu m, and the average particle size of the small-particle shale sample is 50-100 mu m;
(2) Mixing the shale sample obtained in the step (1) with the simulated fracturing fluid according to the mass ratio of (3-6) to obtain a soaking fluid; the mineralization degree of the simulated fracturing fluid is 13000-18000mg/L;
(3) Repeatedly measuring and analyzing the ion content change of each ion in the soaking liquid obtained in the step (2), and determining key ions; the time interval for the repeated measurements is 3-6 days; the endpoint of the repeated measurement is: the absolute difference epsilon of key ions in the adjacent two measurement results is less than or equal to 0.1; the key ions are ions with the largest ion concentration fluctuation range in the soaking liquid;
(4) And (3) calculating the specific surface area and the fracture surface area of the well fracture system according to the concentration of the key ions obtained in the step (3).
Compared with the prior art, the invention has the following beneficial effects:
(1) The method for calculating the fracturing crack area of the shale gas well based on the liquid phase ion characterization is simple, the operation is simple, no additional mine site construction process flow and equipment are required to be added, the indoor and mine sites are easy to realize, and the cost can be greatly saved;
(2) The calculation method of the shale gas well fracturing crack area based on liquid phase ion characterization simultaneously considers the influence of the ion content change in the flowback fluid, the contact area of the shale reservoir and the fracturing fluid and the mineralization degree of the fracturing fluid on the ion content change of the flowback fluid.
Drawings
FIG. 1 is a graph showing the change rule of chloride ions according to example 1 of the present invention;
fig. 2 is a schematic diagram of the data fitting process according to example 1 of the present invention.
Detailed Description
The technical scheme of the invention is further described by the following specific embodiments. It will be apparent to those skilled in the art that the examples are merely to aid in understanding the invention and are not to be construed as a specific limitation thereof.
Example 1
The embodiment provides a shale gas well fracturing fracture area calculating method based on liquid phase ion characterization, which comprises the following steps:
(1) Vibrating and sieving with a combination of 50 mesh, 80 mesh, 100 mesh, 150 mesh, 200 mesh and 250 mesh screens, and drying at 80 ℃ for 25 hours until the shale sample is constant in weight, so that shale scraps are divided into a large-particle shale sample, a medium-particle shale sample, a small-particle shale sample and a small-particle shale sample; the average particle size of the large particle shale sample is 550 microns, the average particle size of the medium particle shale sample is 225 microns, the average particle size of the small particle shale sample is 165 microns, and the average particle size of the small particle shale sample is 82 microns;
(2) Mixing the shale sample obtained in the step (1) with the simulated fracturing fluid in a mass ratio of 1:5 to obtain a soaking fluid; the mineralization degree of the simulated fracturing fluid is 15000mg/L; the mass of the simulated fracturing fluid is 500g;
(3) Repeatedly measuring and analyzing the ion content change of each ion in the soaking liquid obtained in the step (2), and determining key ions; the time interval for the repeated measurements is 5 days; the endpoint of the repeated measurement is: the absolute difference epsilon of key ions in the adjacent two measurement results is less than or equal to 0.1; the key ions are ions with the largest ion concentration fluctuation range in the soaking liquid;
wherein the ion content variation of the large particle shale sample is shown in table 1, the ion content variation of the medium particle shale sample is shown in table 2, the ion content variation of the small particle shale sample is shown in table 3, and the ion content variation of the small particle shale sample is shown in table 4;
analyzing the ion content change of each shale sample, and ending the repeated measurement after the repeated measurement is carried out for 5 times, wherein the key ions in the embodiment are chloride ions as shown in the analysis data; the change rule of the chloride ions is shown in figure 1;
TABLE 1
TABLE 2
TABLE 3 Table 3
TABLE 4 Table 4
(4) And (3) calculating the specific surface area and the fracture surface area of the well fracture system according to the concentration of the key ions obtained in the step (3).
The specific surface area of the large-particle shale sample obtained in the step (1) is as follows:
the specific surface area of the medium-particle shale sample obtained in the step (1) is as follows:
the specific surface area of the small-particle shale sample obtained in the step (1) is
The specific surface area of the micro-particle shale sample obtained in the step (1) is
Calculating a first coefficient and a second coefficient by adopting a data fitting method through the specific surface area of the shale sample and the final concentration of the key ions in the soaking liquid obtained in the step (2), wherein a data fitting diagram is shown in figure 2;
calculated, the first coefficient α=0.0957, and the second coefficient β=0.0003;
specific surface area S of the well fracture system Ratio of The method comprises the following steps:
S ratio of ＝αe βCi ＝0.0957e 0.003Ci
And Ci is the ion concentration of chloride ions in the fracturing fluid, wherein the chloride ion concentration is the average value of the part with the minimum slope of the chloride ion concentration content change curve in the period from the beginning to the ending of the shale gas well. The changes in chloride ion content in the fracturing fluid during the well opening period described in this example are shown in table 5;
TABLE 5
As can be seen from analysis Table 5, the ion concentration of chloride ions in the fracturing fluid was 10130mg/L, and thus the specific surface area S of the well fracture system Ratio of The method comprises the following steps:
S ratio of ＝αe βCi ＝0.0957e 0.003ci ＝1.999cm 2 /g
Shale fracture surface area S provided in this embodiment Watch (watch) The method comprises the following steps:
S watch (watch) ＝S Ratio of ×V Pressing ×ρ Pressing ＝1.999×30157.25×1.04×10 5 ＝6.269×10 9 m 2
In conclusion, the calculation method provided by the invention for immersing the rock in the fracturing fluid firstly analyzes the change rules of the pages with the same mass and different surface areas in an indoor experimental mode, and calculates the change rules of the ion contents of the shale with different specific surface areas in the fracturing fluid. And then the surface area of the crack is calculated by detecting the ion change condition after pressure measurement on site. The calculation method is simple, the operation is simple, no additional mine site construction process flow and equipment are required to be added, the indoor and mine sites are easy to realize, and the cost can be greatly saved.
The applicant declares that the above is only a specific embodiment of the present invention, but the scope of the present invention is not limited thereto, and it should be apparent to those skilled in the art that any changes or substitutions that are easily conceivable within the technical scope of the present invention disclosed by the present invention fall within the scope of the present invention and the disclosure.
Claims (18)
1. The calculation method of the fracturing fracture area of the shale gas well based on the liquid phase ion characterization is characterized by comprising the following steps:
(1) Sieving shale scraps and drying to obtain shale samples;
(2) Mixing the shale sample obtained in the step (1) with a simulated fracturing fluid to obtain a soaking fluid;
(3) Periodically analyzing the ion content change of each ion in the soaking liquid obtained in the step (2), and determining key ions; the periodic analysis is as follows: repeatedly measuring the ion content of each ion in the soaking liquid obtained in the step (2); the endpoint of the repeated measurement is: the absolute difference epsilon of key ions in the adjacent two measurement results is less than or equal to 0.1, wherein the calculation formula of the absolute difference epsilon is as follows:
wherein a is the concentration of key ions obtained by the first measurement in the two adjacent measurement processes; b is the concentration of key ions obtained by the second measurement in the adjacent two measurement processes;
the key ions are ions with the largest ion concentration fluctuation range in the soaking liquid;
(4) Calculating the specific surface area and the fracture surface area of the well fracture system according to the concentration of the key ions obtained in the step (3);
specific surface area S of the well fracture System of step (4) Ratio of The calculation formula of (2) is as follows:
S ratio of ＝αe βCi
Wherein alpha is a first coefficient, beta is a second coefficient, e is a natural logarithm, and Ci is the ion concentration of key ions in the fracturing fluid; alpha and beta are calculated by adopting a data fitting method through the specific surface area of the shale sample and the key ion concentration in the soaking liquid obtained in the step (2);
step (4) the fracture surface area S Watch (watch) The calculation formula of (2) is as follows:
S watch (watch) ＝S Ratio of ×V Pressing ×ρ Pressing
Wherein V is Pressing Is the volume of fracturing fluid in a shale gas well, ρ Pressing Is the density of the fracturing fluid.
2. The computing method of claim 1, wherein the shale samples of step (1) comprise large particle shale samples, medium particle shale samples, small particle shale samples, and small particle shale samples.
3. The method of computing according to claim 2, wherein the large particle shale sample has an average particle size of 400-500 μιη.
4. The method of computing according to claim 2, wherein the medium particle shale sample has an average particle size of 200-250 μιη.
5. The method of computing according to claim 2, wherein the small particle shale sample has an average particle size of 150-200 μιη.
6. The method of computing according to claim 2, wherein the average particle size of the fine particulate shale sample is 50-100 μm.
7. The method according to claim 1, wherein the screening in step (1) is carried out by using a sun screen having a mesh number of 50 to 250 mesh.
8. The method according to claim 1, wherein the temperature of the drying in step (1) is 60-80 ℃.
9. The method according to claim 1, wherein the drying time in step (1) is not less than 24 hours.
10. The method of claim 1, wherein the end point of the drying of step (1) is a shale sample constant weight.
11. The method of claim 1, wherein the shale sample to simulated fracturing fluid mass ratio of step (2) is 1 (3-6).
12. The method of claim 1, wherein the simulated fracturing fluid of step (2) has a mineralization of 13000-18000mg/L.
13. The computing method of claim 1, wherein the time interval for repeating the measurement is 3-6 days.
14. According to claimThe calculation method of claim 1, wherein the calculation formula S of the specific surface area of the shale sample Page ratio The method comprises the following steps:
wherein S is Page(s) For the surface area of shale sample, m Pressing To simulate the quality of fracturing fluid.
15. The computing method of claim 1, wherein the surface area S of the shale sample Page(s) The calculation formula of (2) is as follows:
wherein V is Page(s) And d is the average particle size of the shale sample.
16. The method of computing according to claim 1, wherein the volume V of the shale sample Page(s) The calculation formula of (2) is as follows:
wherein m is Page(s) For the mass of shale sample ρ Page(s) Is the density of the shale sample.
17. The computing method of claim 1, wherein the volume V of fracturing fluid in the rock-gas well Pressing The calculation formula of (2) is as follows:
V pressing ＝V Into (I) -V Return
Wherein V is Into (I) For the amount of fracturing fluid entering the well, V Return The fracturing fluid is returned after the fracturing.
18. The calculation method according to any one of claims 1 to 17, characterized in that it comprises the steps of:
(1) The shale scraps are screened by a 50-250 mesh sieve and then dried for more than 24 hours at the temperature of 60-100 ℃ until the weight of the shale sample is constant, so that a large-particle shale sample, a medium-particle shale sample, a small-particle shale sample and a small-particle shale sample are obtained; the average particle size of the large-particle shale sample is 400-500 mu m, the average particle size of the medium-particle shale sample is 200-250 mu m, the average particle size of the small-particle shale sample is 150-200 mu m, and the average particle size of the small-particle shale sample is 50-100 mu m;
(2) Mixing the shale sample obtained in the step (1) with the simulated fracturing fluid according to the mass ratio of (3-6) to obtain a soaking fluid; the mineralization degree of the simulated fracturing fluid is 13000-18000mg/L;
(3) Repeatedly measuring and analyzing the ion content change of each ion in the soaking liquid obtained in the step (2), and determining key ions; the time interval for the repeated measurements is 3-6 days; the endpoint of the repeated measurement is: the absolute difference epsilon of key ions in the adjacent two measurement results is less than or equal to 0.1; the key ions are ions with the largest ion concentration fluctuation range in the soaking liquid;
(4) And (3) calculating the specific surface area and the fracture surface area of the well fracture system according to the concentration of the key ions obtained in the step (3).
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| CA3058597A1 (en) * | 2017-03-31 | 2018-10-04 | Schlumberger Canada Limited | Method of hydraulic fracturing with fibre-loaded hydraulic fluid |
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| CN105651966A (en) * | 2016-01-18 | 2016-06-08 | 山东科技大学 | Shale oil and gas high-quality reservoir stratum evaluation method and parameter determination method |
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