An experimental test method for the water imbibition and hydration ability of shale

Abstract

The present invention discloses an experimental test method for the water imbibition and hydration ability of shale, which includes: (1) processing the core, and testing to obtain the basic parameters of the core after drying; (2) setting the confining pressure and temperature of the experiment according to the shale reservoir conditions, using a metering tube to record the imbibition amount corresponding to different times, and calculating the imbibition factor and the hydration ability. The present invention designs an experimental test method for the water imbibition and hydration ability of shale that simultaneously considers the influence of formation confining pressure and formation temperature, can simultaneously and quantitatively test the water imbibition and hydration ability of shale, and for the first time quantitatively characterizes the microfracture pore volume before and after shale imbibition, overcoming the important influence of the microfracture pore volume on the hydration ability that was ignored in the prior art.

Description

Technical Field

[0001] The present invention relates to the field of oil and gas engineering, and in particular to an experimental test method for the water imbibition and hydration ability of shale during the development of shale gas reservoirs. Background Art

[0002] The shale gas revolution has not only accelerated the energy independence of the United States, but also pushed the wave of the energy revolution to the whole world. China is extremely rich in shale gas resources. The total national natural gas geological volume is 210 trillion cubic meters, of which shale gas is 80.2 trillion cubic meters, and the development potential is huge. Multi-stage multi-cluster volume fracturing of horizontal wells is the key technology for the efficient development of shale gas.

[0003] Different from conventional sandstones, due to the differences in geological characteristics and fracturing processes, etc., shale gas wells show special flowback characteristics after wellbore compaction: the gas production rate is negatively correlated with the flowback rate, the water production rate decreases and the gas production rate increases after shut-in, and the flowback rate difference is large, etc. (Zhang Tao, Li Xiangfang, Yang Lifeng. Influence of well shut-in time on the flowback rate and productivity of shale gas wells [J]. Natural Gas Industry, 2017, 37(8): 48-58). At present, due to the special flowback characteristics of shale, it is difficult to answer the question of whether well shut-in is needed after volume fracturing of shale gas wells, which affects the continuous and efficient development of shale gas. In the initial stage of well shut-in of shale gas wells, under the combined action of various factors such as capillary pressure, osmotic pressure, formation confining pressure, and formation temperature, the fracturing fluid undergoes water imbibition into the shale reservoir, and at the same time, the fracturing fluid undergoes hydration with the clay minerals in the shale, generating new microfractures, which further promotes the imbibition of the fracturing fluid into the shale matrix. The interaction between shale and the fracturing fluid is an important reason for the above special flowback characteristics of the continuous transformation of the shale reservoir. Therefore, accurate testing of the water imbibition ability and hydration ability of shale has important guiding significance for answering whether well shut-in is needed for shale gas wells and optimizing the flowback system.

[0004] Studies have shown that shale develops multi-scale micro-nano pores and is rich in clay minerals. The ability of aqueous imbibition and hydration is affected by factors such as reservoir confining pressure, temperature, and time. However, the experimental studies in the existing technologies do not consider these factors simultaneously, and most of them focus on separately studying the law of aqueous imbibition in shale and the change of the microscopic pore structure of shale hydration under normal temperature and pressure. The specific content is as follows: (1) Makhanov et al. (Makhanov K, Habibi A, Dehghanpour H, et al. Liquid uptake of gas shales: A workflow to estimate water loss during shut-in periods after fracturing operations[J]. Journal of Unconventional Oil and Gas Resources, 2014, 7:22-32) tested the imbibition ability of shale by measuring the change of mass with time after self-imbibition of shale with a balance. The experimental results showed that the self-imbibition ability along the parallel bedding direction of shale was much greater than that along the perpendicular bedding direction. (2) Yang et al. (Yang L, Ge H, Shi X, et al. Experimental and numerical study on the relationship between water imbibition and salt ion diffusion in fractured shale reservoirs[J]. Journal of Natural Gas Science and Engineering, 2017, 38:283-297) obtained the law of the change of self-imbibition amount with time for different shale samples through spontaneous imbibition experiments and analyzed the correlation between the self-imbibition amount and ore components. Among them, the self-imbibition amount was proportional to the total amount of clay, the content of I / S mixed layer, and the content of illite, and inversely proportional to the content of quartz and organic matter. (3) Xue Huaqing et al. (Xue Huaqing, Zhou Shangwen, Jiang Yali, et al. Influence of hydration on microscopic structure and physical properties of shale[J]. Petroleum Exploration and Development, 2018, 45(06):157-163.) obtained through the SEM experiment on the Longmaxi Formation shale that hydration had no obvious effect on the pore structure of shale organic matter, and the induced microfractures mainly extended and expanded along the bedding between inorganic minerals. And through the CT technology to scan the shale under different water saturation conditions, it was obtained that the hydration intensity was controlled by the development degree of primary fractures. The more developed the primary fractures were, the stronger the hydration was.

[0005] None of the above methods comprehensively consider the influence of reservoir confining pressure and temperature on shale aqueous imbibition and hydration. Shales are usually high-temperature and high-pressure reservoirs. It is difficult to answer whether induced microfractures can be generated by shale aqueous imbibition under the conditions of real reservoir confining pressure and temperature. There is currently no experimental method to consider these factors simultaneously, and the existing technologies mostly conduct qualitative analysis on the hydration ability of shales. Therefore, it is necessary to develop an experimental test method for the aqueous imbibition and hydration ability of shales under the conditions of real reservoir confining pressure and temperature, so as to provide a scientific basis for optimizing the flowback regime of shale gas wells. Summary of the Invention

[0006] The purpose of the present invention is to overcome the defects existing in the prior art and provide an experimental test method for the aqueous imbibition and hydration ability of shales.

[0007] To achieve the above technical objectives, the present invention provides the following technical solutions.

[0008] An experimental test method for the aqueous imbibition and hydration ability of shales, comprising:

[0009] (1) Processing the core, and testing to obtain the basic parameters of the core after drying;

[0010] (2) Setting the confining pressure and temperature of the experiment according to the shale reservoir conditions, using a metering tube to record the imbibition amounts corresponding to different times, and calculating the imbibition factor and the hydration ability.

[0011] Further, the basic parameters of the core in step (1) include the porosity permeability k o , the proportion V of the initial microfracture pore volume fo , and the nuclear magnetic resonance signal area S before the experiment b .

[0012] Further, a helium porosity automatic measuring instrument and an ultra-low permeability measuring instrument are respectively used to test the porosity and permeability k o of the dried core in step (1).

[0013] Further, a nano-CT scanner is used to test and obtain the proportion V of the initial microfracture pore volume of the core fo .

[0014] Further, a low-field nuclear magnetic resonance instrument is used to test the T2 spectrum curve of the core and obtain the nuclear magnetic resonance signal area S b of the core.

[0015] Further, the calculation method of the imbibition factor R is:

[0016]

[0017] In the formula: R is the imbibition factor, dimensionless; Q is the imbibition volume, cm 3 ; S a is the area of the nuclear magnetic resonance signal after the experiment, dimensionless; S b is the area of the nuclear magnetic resonance signal before the experiment, dimensionless; is the porosity of the rock sample before the experiment, %; A is the imbibition area, cm 2 ; L is the core length, cm.

[0018] Furthermore, in step (2), a low-field nuclear magnetic resonance device is used for real-time online monitoring to obtain the area S of the nuclear magnetic resonance signal of the core after the experiment a .

[0019] Furthermore, the calculation method of the hydration ability in step (2) is as follows:

[0020]

[0021] In the formula: H is the hydration factor, dimensionless; V f is the proportion of the microfracture pore volume in the core after the experiment, %; V fo is the proportion of the microfracture pore volume in the core before the experiment, %; is the porosity of the core after the experiment, %; k1 is the permeability of the core after the experiment, mD; is the porosity of the core before the experiment, %; k o is the permeability of the core before the experiment, mD.

[0022] Compared with the prior art, the beneficial effects of the present invention are as follows:

[0023] (1) The present invention designs an experimental test method for simultaneously considering the influence of formation confining pressure and formation temperature on the aqueous imbibition and hydration ability of shale, which can simultaneously and quantitatively test the aqueous imbibition and hydration ability of shale.

[0024] (2) The present invention first quantitatively characterizes the microfracture pore volume before and after shale imbibition, overcomes the important influence of the microfracture pore volume on the hydration ability ignored in the prior art, and the evaluation result is more reliable and accurate, greatly reducing the test cost of evaluating the hydration ability by using microseismic monitoring in the oilfield. Description of the Drawings

[0025] Figure 1 is a schematic diagram of the experimental device for testing the aqueous imbibition and hydration ability of shale of the present invention.

[0026] Figure 2 is a physical diagram of the rock sample before the aqueous imbibition and hydration experiment of shale of the present invention.

[0027] Figure 3 This is a physical diagram of the rock sample after the shale aqueous imbibition and hydration experiments of the present invention. Specific Embodiments

[0028] The present invention will be further described below with reference to the accompanying drawings and embodiments.

[0029] As Figure 1 shown, the experimental test device for the shale aqueous imbibition and hydration ability adopted by the present invention mainly includes a metering tube 1, a sealing liquid 2, a self-aspirating liquid 3, a straw 4, a core 5, a core holder 6, a heating box 7, a heat preservation sleeve 8, a confining pressure pump 9, a cylindrical spacer 10, and a core holder outlet valve 11.

[0030] Among them, the self-aspirating liquid 3 is placed in the metering tube, and the sealing liquid 2 is arranged on the upper surface of the self-aspirating liquid 3 in the metering tube 1 to prevent the self-aspirating liquid 3 from volatilizing. The metering tube 1 is connected to the core holder 6 through a pipeline, and a straw 4 is arranged at the connection position. The core 5 is placed in the core holder 6. When self-aspiration occurs, one end face of the core 5 contacts the self-aspirating liquid 3, and the other end face of the core 5 contacts the cylindrical spacer 10. During the experiment, confining pressure is loaded on the core 5 through the confining pressure pump 9, the core 5 is heated through the heating box 7, and a constant temperature is maintained through the heat preservation sleeve 8; a diversion groove is arranged on the contact surface between the cylindrical spacer 10 and the core 5, and there is a hole 10-1 for fluid flow at the center of the circular spacer 10, and the self-aspirating liquid 3 can flow to the core holder outlet valve 11 through the hole 10-1. The maximum loading temperature of the experimental equipment is 150°C, the maximum stress is 50 MPa, the stress control accuracy is 0.01 MPa, and the stress holding time is greater than 24 h.

[0031] In addition, the core holder can also be connected to a low-field nuclear magnetic resonance device, and the low-field nuclear magnetic resonance device scans the core holder area and measures and obtains different time T2 spectrum curves and the total peak area corresponding to the T2 spectrum curves.

[0032] Using the experimental device provided in the Figure 1 accompanying drawings, the present application provides an experimental test method for the shale aqueous imbibition and hydration ability, including:

[0033] (1) Processing the core and testing to obtain the basic parameters of the core after drying;

[0034] First, the core of the shale reservoir section is processed into a standard rock sample, and the basic parameters before the experiment of the rock sample are tested, including the initial proportion of the microfracture pore volume, porosity, permeability, and the low-field nuclear magnetic resonance signal area.

[0035] When processing the core, the rock in the shale reservoir section can be processed into a standard core with a diameter of 2.5 cm and a length of 5 cm. Calculate the imbibition area of the core as A according to the core end face size, and the core length is the experimentally measured length L. Place the standard core in an oven at 100 °C and dry it to a constant weight.

[0036] Use a helium porosity automatic measuring instrument and an ultra-low permeability measuring instrument to test the porosity and permeability of the dried core respectively.

[0037] Use a nano-CT scanner to scan the dried rock sample to obtain the proportion V of the initial microfracture pore volume in the rock sample before the experiment. fo 。

[0038] Use a low-field nuclear magnetic resonance instrument to test the T2 spectrum curve of the dried shale core to obtain the nuclear magnetic resonance signal area S of the original sample. b 。

[0039] (2) Set the confining pressure and temperature of the experiment according to the shale reservoir conditions, use a metering tube to record the imbibition amount corresponding to different times, and calculate the imbibition factor and hydration ability.

[0040] When conducting the experiment, the confining pressure and temperature of the experiment can be set according to the shale reservoir conditions. Use a metering tube to record the imbibition amount corresponding to different times, and calculate the imbibition factor and hydration ability.

[0041] Specifically, determine the loading conditions for the shale imbibition experiment according to the formation stress and formation temperature in the shale reservoir section. Install the scanned dried core into the core holder, and use a confining pressure pump to load an initial confining pressure of 5 MPa on the core;

[0042] Use a heating box to heat the core and the core holder to the determined experimental temperature;

[0043] Draw the self-aspirating liquid fracturing fluid into the metering tube through a straw. After the liquid level reaches around the 0 scale line, close the straw and use oil as the sealing liquid. Record the initial liquid level position, record the liquid level position every 0.5 h, and the difference between the two liquid level positions is the imbibition amount Q of the shale during this time period. The test time is 10 d.

[0044] Use a low-field nuclear magnetic resonance device to monitor the shale imbibition process in real time and obtain the nuclear magnetic resonance signal area S of the rock sample after the experiment. a 。

[0045] Use a nano-CT scanner to test the proportion of the microfracture pore volume in the rock sample after the experiment, and test the porosity and permeability of the rock sample after the experiment. Calculate the hydration factor and evaluate the hydration ability, so as to achieve the purpose of simultaneously evaluating the water-phase imbibition and hydration abilities of shale.

[0046] Among them, according to the imbibition amount measured by experiment and the area of nuclear magnetic resonance signal, the imbibition capacity of the aqueous phase is calculated. The larger the value, the stronger the imbibition capacity of the aqueous phase. The calculation expression is as follows:

[0047]

[0048] In the formula: R is the imbibition factor, dimensionless; Q is the imbibition amount, cm 3 ; A is the imbibition area, cm 2 ; L is the core length, cm; is the porosity of the rock sample before the experiment, %; S b is the area of the nuclear magnetic resonance signal of the rock sample before the experiment, dimensionless; S a is the area of the nuclear magnetic resonance signal of the rock sample after the experiment, dimensionless.

[0049] After the experiment, use nano-CT to scan the rock sample after the experiment to measure the proportion V of the microfracture pore volume after 10 days f , the porosity of the rock sample and the permeability k1;

[0050] Using the microfracture pore volume, porosity and permeability of the shale before and after the experiment, define the hydration factor to characterize the shale hydration ability. The larger the value, the stronger the hydration ability. The calculation expression is as follows:

[0051]

[0052] In the formula: H is the hydration factor, dimensionless; V f is the proportion of the microfracture pore volume of the core after the experiment, %; V fo is the proportion of the microfracture pore volume of the core before the experiment, %; is the porosity of the core after the experiment, %; k1 is the permeability of the core after the experiment, mD; is the porosity of the core before the experiment, %; k o is the permeability of the core before the experiment, mD.

[0053] In order to enable those skilled in the art to more fully understand the technical solutions and advantages of the present application. The following takes a shale well in the southern Sichuan area of the Sichuan Basin as an example to describe in detail the specific implementation manner of the present invention. Specifically as follows:

[0054] Process the core of the shale reservoir section into a standard rock sample, and test the basic parameters of the rock sample before the experiment, including the initial proportion of the microfracture pore volume, porosity, permeability and the area of low-field nuclear magnetic resonance signal.

[0055] (a) Core preparation: The actual downhole core was taken from the middle of the reservoir section at 2500 - 2560 m in Well WY1 and made into a standard core with a diameter of 2.5 cm and a length of 5 cm. It was placed in an oven at 100 °C and dried to a constant weight. According to the core end face size, the imbibition area A of the core was calculated to be 4.9 cm 2 , and the core length was the experimentally measured length L of 5 cm;

[0056] (b) Testing of basic shale parameters before the experiment: The porosity of the dried core was measured using a helium porosity automatic measuring instrument and an ultra - low permeability measuring instrument respectively. The porosity was 8.6% and the permeability k o was 0.0058 mD.

[0057] (c) Initial pore volume testing: The dried rock sample was scanned using a nano - CT scanner to obtain the proportion V fo of the initial micro - fracture pore volume in the rock sample before the experiment, which was 0.02%.

[0058] (d) Using a low - field nuclear magnetic resonance instrument to test the T2 spectrum curve of the dried shale core, and obtaining the nuclear magnetic resonance signal area S b of the original sample, which was 5780.

[0059] According to the geological parameters of the shale reservoir, the confining pressure and temperature of the experiment were set, and the imbibition and hydration experiments were carried out. The imbibition liquid volume corresponding to different times was recorded using a metering tube, and the imbibition factor was calculated to evaluate the aqueous imbibition ability of the shale. The specific contents are as follows:

[0060] (a) The formation temperature of the shale in Well WY1 was 85 °C and the formation confining pressure was 20 MPa, which were determined as the experimental temperature and pressure. The scanned rock sample was loaded into a core holder, and an initial confining pressure of MPa was applied to the core using a confining pressure pump;

[0061] (b) The self - sucking liquid fracturing fluid was sucked into the metering tube through a straw. After the liquid level reached around the 0 scale line, the straw was closed, and oil was used as the sealing liquid. The initial liquid level position was recorded, and the liquid level position was recorded every 0.5 h. When the experimental test time reached 10 d, the imbibition volume Q of the shale sample was 1.56 cm 3 .

[0062] (c) Using a low - field nuclear magnetic resonance device to monitor the shale imbibition process in real - time online, and obtaining the nuclear magnetic resonance signal area S a of the rock sample after the experiment, which was 27050.

[0063] (d) According to the imbibition volume and nuclear magnetic resonance signal area measured in the experiment, as well as the basic parameters of the rock sample, the imbibition factor was calculated to be 2.08 using formula (1).

[0064] Use a nano-CT scanner to test the proportion of the microfracture pore volume in the rock sample after the experiment, and test the porosity and permeability of the rock sample after the experiment. Calculate the hydration factor to evaluate the hydration ability, so as to achieve the purpose of simultaneously evaluating the water imbibition and hydration abilities of shale. The specific contents are as follows:

[0065] (a) Testing of the basic parameters of the shale after the experiment: Use a nano-CT scanner to test the proportion of the microfracture pore volume V after 10 days of the rock sample after the experiment f is 2.17%, the porosity of the rock sample is 10.3% and the permeability k1 is 0.0126 mD;

[0066] (b) According to the proportion of the microfracture pore volume, porosity and permeability of the shale before and after the experiment, use formula (2) to calculate the hydration factor to be 286.78.

[0067] The present invention is specifically described above through embodiments. It is necessary to point out here that this embodiment is only a preferred embodiment of the present invention, and does not impose any limitation on the present invention, nor is it limited to the form disclosed herein, and should not be regarded as excluding other embodiments. Any changes and simple variations made by those skilled in the art without departing from the technical idea and scope of the present invention shall fall within the protection scope of the technical solution of the present invention.

Claims

1. An experimental test method for the water imbibition and hydration ability of shale, comprising: (1) Processing the core, and testing to obtain the basic parameters of the core after drying; (2) Setting the confining pressure and temperature of the experiment according to the shale reservoir situation, recording the imbibition amount corresponding to different times by using a metering tube, and calculating the imbibition factor and the hydration ability; The calculation method of the imbibition factor R is: Where: R is the imbibition factor, dimensionless; Q is the imbibition amount, cm 3 ; S a is the area of the nuclear magnetic resonance signal after the experiment, dimensionless; S b is the area of the nuclear magnetic resonance signal before the experiment, dimensionless; is the porosity of the rock sample before the experiment, %; A is the imbibition area, cm 2 ; L is the core length, cm; The calculation method of the hydration ability is: Where: H is the hydration factor, dimensionless; V f is the proportion of the pore volume of microfractures in the core after the experiment, %; V fo is the proportion of the pore volume of microfractures in the core before the experiment, %; is the porosity of the core after the experiment, %; k1 is the permeability of the core after the experiment, mD; is the porosity of the core before the experiment, %; k o is the permeability of the core before the experiment, mD.

2. The experimental test method for the shale water imbibition and hydration ability according to claim 1, characterized in that, The core basic parameters in step (1) include the porosity of the core permeability k o , the proportion of the initial microfracture pore volume V fo , the nuclear magnetic resonance signal area S before the experiment b .

3. The experimental test method for the shale water imbibition and hydration ability according to claim 1, characterized in that, The initial microfracture pore volume fraction V of the core was measured by using a nano-CT scanner fo .

4. The experimental test method for the shale water imbibition and hydration ability as described in claim 1, wherein Use a low-field nuclear magnetic resonance instrument to test the T2 spectrum curve of the core and obtain the nuclear magnetic resonance signal area S of the core b .

5. The experimental test method for the shale water imbibition and hydration ability as described in claim 1, wherein In step (2), real-time on-line monitoring is carried out by using a low-field nuclear magnetic resonance device to obtain the nuclear magnetic resonance signal area S of the core after the experiment a .

6. The experimental test method for the shale water imbibition and hydration ability as described in claim 1, characterized in that, Use a helium porosity automatic measuring instrument and an ultra-low permeability measuring instrument to respectively measure the porosity of the dried core in step (1) and the permeability k o .

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