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. 2024 Apr 25;9(18):20196–20205. doi: 10.1021/acsomega.4c00498

Research on the Shale Reservoir Sensitivity by Using the Mineral Analysis Method

Yinhua Liu †,‡, Jianguang Wei §,∥, Jingde Lin †,‡, Ying Yang §,∥,*, Wentao Ma †,‡, Jiangtao Li §,∥, Peihua Zhao †,‡, Quanshu Zeng ⊥, Jianjun Wu †,‡
PMCID: PMC11079880  PMID: 38737071

Abstract

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Shale reservoirs have diverse mineral types, and analyzing the sensitivity of the mineral composition to shale pores is of great scientific and engineering significance. In this paper, first, X-ray diffraction (XRD) experiments on shale mineral compositions are carried out, and the characteristics of pore structure changes after shale mineral compositions interacted with external fluids (slick water and backflow fluid) are elucidated. Then, the effects of quartz, kaolinite, and pyrite on the pore structure and permeability of shale on the susceptibility to slick water are studied. The results show that (a) quartz and clay minerals are the dominant constituents of each core, with some cores containing minor amounts of plagioclase feldspar and rhodochrosite. (b) The composition of the shale changed significantly following the action of external fluids. The average quartz content of pure shale decreased from 31.62% to 29.1%. The average content of quartz in siliceous shale decreased from 36.53% to 33.5%. The average content of quartz in carbonaceous shale decreased from 9.15% to 8.05%. (c) Factors affecting the sensitivity of shale pore structure and permeability to slick water are mainly quartz, kaolinite, and pyrite. The contents of quartz, kaolinite, and pyrite decreased by an average of 5.1%, 4.6%, and 0.9%, respectively, after slick water action.

1. Introduction

The phenomenon of permeability decline in oil and gas reservoirs during drilling, completion, production enhancement, and production is called reservoir damage.1−3 The damage of oil and gas reservoirs is closely related to the protection technology,4,5 and understanding the reservoir damage mechanism is the theoretical basis for formulating reservoir protection, prevention, and control technology.6−8

Damage to oil and gas reservoirs is essentially a decrease in permeability caused by changes in the pore structure of the rock.9−11 Diagnosis and determination of damage mechanisms need to be based on core analysis, sensitivity assessment, working fluid damage simulation experiments, and field evaluation.12−14 Specific aspects, types, and processes of damage occurrence are revealed through comprehensive analysis.15−18 A large number of scholars believe that the intrusion of working fluid filtrate is the main damage factor in low permeability tight gas reservoirs.19−22 The permeability of the core matrix in such gas reservoirs is very low, and the median radius of the throat is less than 1 μm, showing high capillary force characteristics.23−25 The initial water saturation of the reservoir is often lower than the bound water saturation, leading to easy retention of the working fluid filtrate intruding into the core and difficult to flow back, which can easily lead to a significant reduction in the gas permeability and the formation of serious water-phase trap damage.26−30 When drilling in the reservoir section, the reservoir damage originates from drilling fluid leakage or filtration under the effect of positive differential pressure in the wellbore and capillary forces.31−35 Intrusion into the solid phase can cause reservoir fractures and pore throat plugging, while intrusion into the liquid phase is prone to sensitivity damage and water-phase trap damage.36−39 The depth of drilling fluid intrusion and the degree of damage increase with the increase of positive differential pressure in the wellbore and drilling time.40−44 Among them, as an important development direction of oil and gas wells, it is crucial to study the damage factors and extent of horizontal wells.45−48 Horizontal wells are an important means to increase the production capacity of oil and gas wells, but in many cases, the actual production capacity of horizontal wells cannot meet the expected plan.49−52 The main fluid-sensitive minerals in shale are clay minerals.53−55 The high content and diverse types of this mineral are important potential factors for shale gas reservoirs.56−61 However, there are variations in the type and content of the mineral in different shale gas reservoirs, leading to different mechanisms and degrees of reservoir damage.62−65

In summary, the effect of fracturing fluids on the sensitivity of shale reservoirs is investigated, and the mechanism of fracturing fluids’ action on the pore scale is analyzed. However, the mineral types and preparation modes of the fracturing fluids are still unclear. In this paper, first, X-ray diffraction (XRD) analysis experiments on shale mineral compositions are conducted to elucidate the characteristics of pore structure changes after shale mineral compositions interact with external fluids. Second, the effects of quartz, kaolinite, and pyrite on the pore structure and permeability of shale on the susceptibility to slick water are elucidated. Finally, the characteristics of the changes in the shale mineral content after reflux fluid interaction are discussed.

2. Sampling Strategy

First, the mineral compositions of the shale matrix cores with different lithologies are numerically analyzed. Then, the formation mechanism and main control factors of the external fluid sensitivity of shale gas reservoirs are elucidated.

Diffraction of X-rays in crystals is the result of coherent scattering of X-rays by electrons in individual atoms in the crystal and the superposition or elimination of mutual interference. A crystal can be used as a grating for X-rays. Coherent scattering by a large number of particles (atoms, ions, or molecules) causes interference of light, which enhances or weakens the intensity of the scattered X-rays. The beams of light with the highest intensity resulting from the interference of a large number of particles superimposed on a scattered wave are called X-ray diffractions. When monochromatic X-rays are incident on a crystal, since the crystal consists of regularly arranged atomic units, the distances between these regularly arranged elements are of the same order of magnitude as the wavelength of the incident X-rays. As a result, X-rays scattered by different atoms interfere with each other, producing strong X-ray diffraction in some specific directions. The orientation and intensity of the diffracted rays in the spatial distribution are closely related to the crystal structure. This is the basic principle of X-ray diffraction.

We carefully installed the prepared sample onto the sample holder and gently fasten it. We pressed the button at the bottom of the two indicator lights on the right side of the front of the machine. At this point, we can slowly and forcefully open the hatch by holding the handle below it. We carefully placed the assembled sample and bracket on the sample stage inside the instrument compartment (this machine is a rotating sample stage, fixed by magnetic adsorption, pay attention to grasping the sample) and adjusted the relative opening position on the bracket to coincide with the opening position on the instrument sample stage. If the starting angle of measurement is relatively low (<10 degrees), an anti air scattering accessory needs to be used. The distance between the blade of the attachment and the surface of the sample is about 1 to 1.5 mm. While greatly reducing the background of air scattering, it is necessary to ensure that the high angle measurement intensity is not affected. After placing the samples, close the hatch.66,67

In this paper, 12 sets of three types of cores were selected from the Daning-Jixian Massif on the eastern margin of the Ordos Basin. XRD mineral composition analysis experiments were carried out. The rock mineral composition of the shale gas reservoirs in the transition between the sea and land was initially elucidated. The basic information on the cores is shown in Table 1.

Table 1. Basic Parameters and Experimental Plan of the Rock Core.

no. shale type well no. core no. length/cm diameter/cm mass/g gas measured permeability/mD test fluid
1 pure shale DJ3–4 4–13–3–1 4.394 2.490 52.6644 0.0440 slick water with variable viscosity (0.4%)
2 pure shale DJ3–4 4–13–6–2 4.082 2.488 48.7768 0.0109 backflow fluid
3 pure shale DJ6–5 24–5–1–1 4.020 2.520 51.5634 0.1942 slick water with variable viscosity (0.4%)
4 pure shale DJ6–5 40–3–2 4.180 2.526 53.8308 0.3543 backflow fluid
5 siliceous shale DJ6–5 29–1–1 3.474 2.512 44.5350 0.4266 slick water with variable viscosity (0.4%)
6 siliceous shale DJ6–5 29–3–1 4.040 2.488 51.0899 0.5666 backflow fluid
7 siliceous shale DJ6–5 51–1–2 4.032 2.524 52.3745 0.0962 slick water with variable viscosity (0.4%)
8 siliceous shale DJ6–5 51–2–2 3.750 2.522 48.6862 0.5339 backflow fluid
9 carbonaceous shale DJ3–4 3–4–2–2 5.380 2.454 41.5771 5.5540 slick water with variable viscosity (0.4%)
10 carbonaceous shale DJ3–4 3–4–2–1 5.100 2.492 47.3796 6.1837 backflow fluid
11 carbonaceous shale DJ6–5 44–3–1 4.090 2.530 35.5366 0.1343 slick water with variable viscosity (0.4%)
12 carbonaceous shale DJ6–5 44–4–2 4.120 2.528 33.5183 0.0188 backflow fluid
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3. Results and Discussion

In this section, the results of quantitative XRD whole-rock tests and the relative quantities of clay minerals from 12 sets of cores of three types are first discussed. On this basis, the coupling influence mechanism of different types of external fluids and shale minerals is analyzed.

3.1. Experimental Results

Tables 2 and 3 show the quantitative whole-rock XRD results and the relative content of clay minerals tested for 12 sets of cores of three types, respectively. Figures 1 and 2 show the results of the comparison of the rock mineral compositions and clay mineral compositions of the 12 sets of cores. From Tables 2 and 3 and Figures 1 and 2, it can be seen that (a) the mineral content of pure shale reservoirs is clay minerals (53.9%) > quartz (31.6%) > pyrite (8.2%) > amorphous (5.3%). (b) The mineral content of siliceous shale reservoirs is clay minerals (61.4%) > quartz (36.5%) > rhodochrosite (1.1%) > plagioclase (1.0%). (c) For carbonaceous shale reservoirs, the mineral content is clay minerals (35.8%) > amorphous minerals (31.8%) > pyrite (23.0%) > quartz (9.2%). In addition, the carbonaceous shale contains small amounts of anatase and calcite. (d) Clay minerals in the shale gas reservoir rocks mainly include kaolinite (21.7% on average), illite (11.6%), chlorite (9.0%), and illite/montmorillonite mixed layer (8.0%), with the clay minerals mainly consisting of illite (21.2%) > kaolinite (20.6%) > illite-montmorillonite mixed layer-illite (11.8%) > chlorite (5.7%) > immonite mixed layer-montmorillonite (2.1%). (e) Clay minerals in the carbonaceous shale are mainly kaolinite (24.6%) > chlorite (8.6%) > illite (2.0%) > illite-monzonite (0.5%).

Table 2. XRD Whole Rock Quantitative Experimental Results.

type quartz feldspar plagioclase calcite noncrystal anatase siderite pyrite clay mineral
pure shale 31.6 A small amount a small amount   5.3   a small amount 8.2 53.9
siliceous shale 36.5   1.0       1.1   61. 4
carbonaceous shale 9.2     a small amount 31.8 a small amount   23.0 35.8
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Table 3. Experimental Results of Relative Quantity of Clay Minerals.

  clay mineral content/%
 mixed layer ratio of illite/montmorillonite
 mixed layer ratio of chlorite/montmorillonite
rock type smectite, S illite, I kaolinite, K chlorite, C mixed layer of illite/montmorillonite, I/S mixed layer of chlorite/montmorillonite, C/S smectite, S% illite, I% smectite, S% chlorite, C%
pure shale   13.7 20.1 12.6     1.1 6.5    
siliceous shale   21.2 20.6 5.7     2.1 11.8    
carbonaceous shale     24.6 8.6     0.5 2.0    
average   11.6 21.7 9.0     8.0    
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Figure 1.

Figure 1

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Comparison of mineral compositions of different cores.

Figure 2.

Figure 2

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Comparison of clay mineral compositions in different cores.

Figure 1 shows the differences in the mineral composition of the different cores. As can be seen in Figure 1, (a) quartz and clay minerals are the main components of each core, with some cores containing small amounts of plagioclase feldspar and rhodochrosite. (b) Cores 3–4 2–02 and 3–4 2–01 contain relatively abundant pyrite with a high amorphous content and relatively low clay mineral and quartz content. Core 44–4–1 contains small amounts of rutile. Core 40–3–1 contains relatively abundant pyrite and minor potassium feldspar. (c) Overall, the carbonaceous shale is relatively rich in pyrite and amorphous minerals and relatively low in quartz. Siliceous shales are rich in quartz and clay minerals. Pure shales are rich in quartz, clay minerals, and small amounts of pyrite. All three types of shale contain traces of plagioclase feldspar and almost no potassium feldspar, and carbonaceous shales have relatively high hydrocarbon potential.

Figure 2 shows the differences in the clay mineral content in the different cores. From Figure 2, it can be seen that (a) overall, the main components of the three shale types are kaolinite, chlorite, and illite. (b) More than half of the carbonaceous shale is composed of kaolinite with minor amounts of chlorite, mixed IM-I layers, and trace amounts of mixed IM-M layers. (c) Pure shale is composed mainly of kaolinite, chlorite, and illite. Siliceous shales are dominated by mixed layers of kaolinite, illite, and IM-I. In addition, the amount of IM-M in all types of shale is so small as to be almost negligible. (c) Core 44–3–2 is composed predominantly of kaolinite with only minor chlorite and IM-I mixed layers. The siliceous shale has a high overall content of illite, with the 51–1–1 core having the highest illite content.

3.2. Discussion and Analysis

Figures 3 and 4 show the experimental results of whole rock and clay minerals of shale gas reservoir rock samples after external fluid action and clay minerals of shale gas reservoir rock samples under external fluid action in 12 sets of cores, respectively.

Figure 3.

Figure 3

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Experimental results of the whole-rock mineral analysis of shale gas reservoir samples after external fluid action.

Figure 4.

Figure 4

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Experimental results of clay minerals in shale gas reservoirs under an external fluid action.

As can be seen in Figure 3, (a) the composition of the shale changed significantly after the action of external fluids. Overall, the main components remain quartz and clay minerals, with a slight decrease in the quartz content. The average content of quartz in pure shale decreased from 31.62% to 29.1%, the average concentration of quartz in siliceous shale decreased from 36.53% to 33.5%, and the average content of quartz in carbonaceous shale decreased from 9.15% to 8.05%. (b) The average content of clay minerals in pure and siliceous shales increased slightly. The average content of clay minerals in pure shale increased from 53.92% to 55.75%, the average content of clay minerals in siliceous shale increased from 61.43% to 62.3%, and the content of carbonaceous shale decreased slightly. The content of pyrite in carbonaceous shale decreased, with the average content decreasing from 45.75% to 41.8%. It can be seen that external fluids can increase the pore permeability of carbonaceous shale to some extent.

From Figure 4, it can be seen that (a) the clay mineral compositions of the various shales have changed significantly after the action of external fluids. The main components are still kaolinite, chlorite, and illite with a decrease in kaolinite content. (b) The average kaolin content of pure shales decreased from 20% to 17.7%. (c) The average concentration of kaolin in siliceous shale decreased from 20.58% to 17.48%. The average concentration of kaolin in carbonaceous shale decreased from 24.55% to 22.58%. The average concentration of chlorite in pure shale increased from 12.62% to 13.85%. The average content of chlorite in siliceous shale increased from 5.73% to 7.43%. The average content of chlorite in carbonaceous shale decreased from 12.25% to 6.7%. (c) Ilmenite content increased in all three types of shale. The average illite content of pure shale increased from 13.72% to 14%. The average content of illite in siliceous shale increased from 21.25% to 23.9%. The average content of Iillite in carbonaceous shale increased from 0 to 3.62%. It can be seen that the external fluid action led to the formation of illite in carbonaceous shale.

Figures 5 and 6 show the experimental results of changes in the whole rock mineral content of shale gas reservoir rock samples after sliding water action. Figure 7 shows the changes in the porosity and permeability of shale reservoirs after sliding water action. From Figures 5–7, it can be seen that (a) the factors affecting the shale porosity structure and permeability sensitivity to sliding water mainly include quartz, kaolinite, and pyrite. (b) The contents of quartz, kaolinite, and pyrite decreased by an average of 5.1%, 4.6%, and 0.9%, respectively, after slick water action. (c) Quartz, kaolinite, and pyrite undergo alkaline hydrolysis and pore enlargement. At the same time, colloids or precipitates are generated. The reaction products can plug reservoir pores and fractures. In addition, hydroxypropylguanidine gum can be adsorbed on kaolinite, damaging the reservoir and leading to a decrease in porosity and permeability in medium and large pores.

Figure 5.

Figure 5

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Experimental results of mineral content changes in rock samples from shale gas reservoirs after water-slide action.

Figure 6.

Figure 6

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Experimental results of changes in clay mineral content following water-slide action.

Figure 7.

Figure 7

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Experimental results of porosity and permeability changes in shale reservoirs under water sliding.

From Figure 5, it can be seen that (a) the mineral compositions of the three types of shale changed significantly after the water-slide action. Quartz content decreased significantly. The content of amorphous minerals and clay minerals increased significantly. (b) The average quartz content of pure shale, siliceous shale, and carbonaceous shale decreased by 6.5%, 5.5%, and 3.4%, respectively. (c) The average content of clay minerals in pure shale and siliceous shale increased by 4.55% and 3%, respectively, while the average content of clay minerals in carbonaceous shale decreased by 0.9%. (c) Increased rutile content in pure and siliceous shales. Carbonaceous shales show a significant decrease in pyrite content and an increase in Barite content. (d) There is a slight increase in the content of rhodochrosite in all three shale types. (e) Significant increase in amorphous content in carbonaceous shale suggests that slick water can increase pore permeability in shale reservoirs.

As can be seen in Figure 6, (a) the clay mineral compositions in the three types of shale changed significantly under the action of slick water. Overall, there was an increase in all four compositions except kaolinite. (b) The average chlorite content in pure, siliceous, and carbonaceous shales increased by 3.5% and 2.5%, respectively, while the average chlorite content in carbonaceous shales decreased by 0.35%. The average content of illite in pure shale, siliceous shale, and carbonaceous shale increased by 2.5%, 4.1%, and 0.9%, in that order. The average content of IM-M in pure shale, siliceous shale, and carbonaceous shale increased by 0.85%, 0.9%, and 0.15%, respectively. The average content of IM-I in pure shale, siliceous shale, and carbonaceous shale increased by 0.9%, 1.2%, and 0.6%, respectively. The average content of clay minerals in pure shale, siliceous shale, and carbonaceous shale decreased by 3.15%, 5.6%, and 5%, respectively.

As can be seen from Figure 7, (a) the pore permeability properties of the shale reservoir changed significantly after the sliding water action. Overall, the total porosity and permeability decreased significantly. In terms of porosity, the micro- and nanopores of all three types of shale were reduced, with a significant decrease in siliceous and carbonaceous shale and a slight decrease in pure shale. The macropores decreased significantly while the small pores increased. This may be due to the transformation of large pores into more small pores after crushing. Due to the unique mechanical properties of carbonaceous shale, macropores decrease by as much as 90%, while both small and mesopores increase significantly, indicating a shift from macropores to mesopores and small pores. For permeability, the contribution of macropores to permeability is usually the most significant. As a result of the severe reduction of macropores in all three types of shales, permeability was significantly reduced. For pure and siliceous shales, an increase in small pores leads to an increase in matrix permeability. Mechanistic permeability is also reduced in carbonaceous shales due to a significant reduction in macroporosity.

Figures 8 and 9 show the experimental results of the change of the total mineral content of shale gas reservoir samples after reflux fluid action. Figure 10 shows the experimental results of the change of porosity and permeability of the shale reservoir after reflux fluid action. From Figures 8–10, it can be seen that (a) there is no significant change in the mineral content of shale after reflux fluid action. (b) The total porosity of different types of shale is not sensitive after reflux fluid action. However, due to hydration, microcracks are produced, leading to an increase in the proportion of large pores and an increase in the core permeability.

Figure 8.

Figure 8

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Experimental results of mineral content changes in shale gas reservoir rock samples after reflux fluid action.

Figure 9.

Figure 9

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Experimental results of changes in clay mineral content following the action of refluxing fluids.

Figure 10.

Figure 10

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Experimental results of porosity and permeability changes in shale reservoirs after reflux fluid action.

As can be seen in Figure 8, the quartz content of all three types of shale, except for sample 51–2–2, tends to increase under the action of the reflux solution. The clay minerals of all three types of shale show a decreasing trend, except for sample 51–2–2. Among these samples, sample 40–3–2 has a severe loss of pyrite under the action of reflux fluid with a loss of up to 8%. The reduction in mineral content can lead to an improvement in the permeability of the samples. (b) For sample 44–4–2, the pyrite content actually increased. The probable reason for this is that the components in the reflux solution react with the material in the reservoir. Sample 51–2–2 shows a decrease in various minerals and an increase in clay minerals in response to the reflux solution. This may favor an increase in the porosity and permeability of such reservoirs.

As can be seen in Figure 9, the content of kaolinite, chlorite, and illite in pure shale decreases significantly in the presence of reflux solution. This can improve the permeability of the sample. Also, the IM-M and IM-I mixed layers show a significant increase. Under certain conditions, the effect of dehydration transformation within the layer can be enhanced and the permeability can be increased. (b) Sample 51–2–2 shows a significant increase in illite content. The possible reason is the chemical reaction between the components in the reflux solution and the substances in the sample. Under the effect of reflux solution, the IM-M content of siliceous shale decreased slightly, while the IM-I content decreased significantly.

As can be seen in Figure 10, the overall porosity and permeability increased under the action of the reflux fluid. Among them, the content of micro- and nanopores in pure shale increased, while the content of small and medium-sized pores decreased to some extent and the content of large pores increased. This may be due to the transformation of small and medium pores into macropores under the action of the reflux fluid. The increase in macropores resulted in a significant increase in permeability, while the decrease in small and medium pores resulted in a decrease in matrix permeability. (b) The content of micro-, nano-, and small pores in the siliceous shale decreases, while the content of meso- and macropores increases significantly. It is possible that micro/nanopores and small pores were mechanically transformed into mesopores by the action of the reflux fluid. The total pore volume remained almost constant, while the decrease in the content of micro/nanopores and small pores may have led to a slight decrease in matrix permeability and permeability. (c) In carbonaceous shale, small, meso-, and macropores show a significant increase, except for a slight decrease in micro- and nanopores. As a result, matrix permeability decreased slightly, while the permeability increased more significantly.

4. Conclusions

In this paper, first, the composition of shale minerals is analyzed experimentally by XRD. Then, the effects of quartz, kaolinite, and pyrite on the pore structure and permeability of shale on the susceptibility to slick water are elucidated. Finally, the characteristics of the shale mineral content changes after the action of reflux fluid are explored. The main findings are as follows:

  • 1.

    Quartz and clay minerals are the dominant constituents of each core, with some cores containing minor amounts of plagioclase feldspar and rhodochrosite. The major constituents of the three shale types are kaolinite, chlorite, and illite. More than half of the carbonaceous shale is composed of kaolinite with minor amounts of chlorite, mixed IM-I layers, and trace amounts of mixed IM-M layers.

  • 2.

    The composition of the shale has changed significantly following the action of external fluids. Overall, the main components remain quartz and clay minerals, with a slight decrease in quartz content. The average quartz content in pure shale decreased from 31.62% to 29.1%, the average concentration of quartz in siliceous shale decreased from 36.53% to 33.5%, and the average quartz content in carbonaceous shale decreased from 9.15% to 8.05%.

  • 3.

    Factors affecting the susceptibility of shale pore structure and permeability to slick water are mainly quartz, kaolinite, and pyrite. The contents of quartz, kaolinite and pyrite decreased by an average of 5.1%, 4.6%, and 0.9%, respectively, after slick water action. Quartz, kaolinite, and pyrite underwent alkaline hydrolysis and pore enlargement.

Acknowledgments

This work was supported by Prospective Basic Technology Research Project of China National Petroleum Corporation Limited (2021DJ2006), the China Postdoctoral Science Foundation (grant no. 2022M710594), and the Natural Science Foundation of Heilongjiang Province (grant no. LH2022E019).

The authors declare no competing financial interest.

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