Experimental Study on the Impact of CO₂ Treatment on Different Lithofacies in Shale Oil Reservoirs

Abstract

CO₂ technology has been progressively used in the development of shale oil. After injection, CO₂ can react with formation water to form carbonic acid, which then reacts with carbonate and silicate minerals, resulting in changes in porosity and permeability. However, there are some debates as to whether the effect of CO₂ improves or damages porosity and permeability. So, in this paper, systematic experiments were carried out to clarify the interaction between CO₂ and shale in different lithofacies and to draw a pertinent conclusion. The results showed that the shale in Qingshankou Formation could be divided into three main lithofacial types: foliaceous shale, laminated feisic shale and laminated diamictic shale. There were relatively more pores, some natural microfractures and small mineral particles in foliaceous shale, a few micropores and large mineral particles in laminated feisic shale, some biogenic calcium carbonate minerals and hardly any micropores in laminated diamictic shale. Due to the diversity of micromorphology and mineral composition, the effects of CO₂ treatment had significant differences. For foliaceous shale, CO₂ treatment had both improving and damaging effects on porosity and permeability; for laminated shale, both porosity and permeability improved significantly. So, it is necessary to identify the main lithofacies of target formation before the application of CO₂ technology in shale oil reservoirs.

1. Introduction

Unconventional oil and gas are the current focuses of oil and gas exploration and development; among them, shale oil is the most strategic replacement resource, with huge development potential [1,2,3]. Restricted by ultra-low porosity and permeability, shale oil reservoirs are facing the problem of rapid production decline in the process of development. The oil recovery factor of shale oil is less than 10%, generally, which is much lower than the average recovery factor of conventional crude oil [4,5,6,7]. In order to slow down the production decay rate and obtain higher oil recovery, it is urgent to explore enhanced oil recovery technology for shale oil.

The ultra-low porosity and permeability of shale oil reservoirs restrict the application of conventional EOR technologies [8,9,10]. On the basis of laboratory experiments and numerical simulation studies, researchers find that huff-and-puff gas injection and surfactant imbibition are the most feasible enhanced oil recovery methods for shale oil [11,12,13,14]. CO₂ injection technology can effectively improve oil recovery through the mechanisms of miscible flooding, viscosity reduction and formation energy supplements, and has received extensive attention from researchers [15,16,17,18,19].

After being injected into a formation, CO₂ can react with formation water to form carbonic acid, which can react with carbonate and silicate minerals in the shale, resulting in changes in reservoir porosity and permeability. However, CO₂ has both positive and negative effects on reservoir porosity and permeability after complex reactions [20,21,22,23,24]. On the one hand, these reactions can dissolve part of the matrix minerals, increasing the matrix porosity effectively. Additionally, this dissolution can increase the size of the seepage channel and improve the pore connectivity, thereby increasing the permeability of shale oil reservoirs. On the other hand, new mineral precipitation will be produced after the interactions between CO₂ and minerals, such as potassium feldspar, albite and chlorite. Additionally, the dissolution of cement causes the migration of mineral particles. Both the precipitation and migration of minerals may block pores and throats and reduce matrix porosity. Furthermore, these cause a decrease in pore connectivity and damage the permeability of shale oil reservoirs.

There are strong vertical heterogeneity and mineral composition differences in the continental shale oil reservoirs of China [25,26,27,28]. So, the changes in porosity and permeability in different formations are significantly different after CO₂ injection. Therefore, it is necessary to carry out systematic experiments to clarify the interaction between CO₂ and shale in different lithofacies, and its effect on the porosity and permeability of shale oil reservoirs. In this paper, the main lithofacial types of the target formation are identified through core observation and X-ray fluorescence (XRF) spectrum analysis. Then, shale samples in different lithofacies are selected for CO₂ soaking experiments. Finally, the influence of CO₂ treatment on shale is explored by X-ray diffraction (XRD) mineral composition analysis, scanning electron microscope (SEM) micromorphology analysis and characterizations of porosity and permeability.

2. Materials and Methods

2.1. Sample Preparation

Our shale samples are from the Qingshankou Formation in the Songliao Basin (Figure 1), which is one of China’s most important continental shale oil reservoirs. The Songliao Basin is located in northeast China, and the Qingshankou Formation in this basin develops high quality shales in which extensive hydrocarbon has been shown. The geological resources in this formation are about 54.6 × 10⁸ t and have huge exploration and development potential. The reservoir of the Qingshankou Formation is mainly shale, with a few sandstone and limestone interbeds, and the formation depth is about 1500–2500 m. The content of brittle minerals is high, and the proportion of clay minerals is 30–60%. The ionic composition of the brine used in the following experiments is shown in

Table 1. Ionic composition of the brine.

Ion	Na+ and K+	Ca2+	Mg2+	Cl−	SO42−	HCO3−
concentration (mg/L)	2320	39	5	1450	307	3420

, measured from the produced water.

The shale samples are processed into small pieces and huge bulk samples by mechanical cutting. Then, the cut surfaces of these bulk samples are polished by an automatic polish–grinding machine. After polishing, the bulk samples are put into an ultrasonic cleaner to remove contaminants and keep the cut surface of these samples flat and clean. These processed small pieces and huge bulk samples are shown in Figure 2a,b.

The SEM samples are cut from target areas of huge bulk samples and the size of these samples is 0.5 cm × 1 cm × 1 cm, processed by mechanical cutting. Then, the SEM samples are fixed to sample holders and their top surfaces are polished with sandpaper. After mechanical polishing, the samples are put into an argon ion polisher for 4 hours’ processing. Finally, the polished samples are plated with a thin layer of carbon on their surfaces. SEM samples are shown in Figure 2c.

The shale samples are processed into core samples by numerically controlled wire cutting, and the size of these core samples is 25 mm in diameter and 50 mm in length. After processing, those core samples that have retained their integrity, have no damage and are fracture-free are chosen and polished with sandpaper to keep their surfaces smooth and their end surfaces flat. Then these samples are put into an oil-cleaning instrument for one week to clean off the crude oil and ensure the samples are clean and damage-free. Processed core samples are shown in Figure 2d and the direction of these samples is parallel to the bedding.

2.2. Experimental Apparatus and Methods

2.2.1. Experimental Apparatus

The element distribution in a large area of each shale sample is measured through the XRF analysis using an M4 TORNADO X-ray fluorescence spectrometric instrument from Bruker, Germany. In this experiment, the area scan method is adopted and the vacuum degree, voltage and current are kept at 20 mbar, 50 kV and 200 μA, respectively.

The pore structures and micromorphologies of the shale samples are measured through SEM analysis, using an Apreo field-emission scanning electron microscopy from ThermoFisher Scientific, USA. The instrument’s maximum resolution is 1 nm under 1 kV. In this experiment, the work distance, voltage and current are kept at 10 mm, 10 kV and 1.6 nA, respectively.

The mineral composition of shale samples is measured through XRD analysis using D/max 2500 PC X-ray diffractometer from Rigaku Corporation, Japan. In this experiment, the average particle size of shale samples is 125–150 μm, and the scanning angle is 3–85° at a scanning speed of 1°/min. The detailed procedures can be found in SY/T5163-2010.

The porosity and permeability of shale samples are measured with helium before and after CO₂ treatment, using an AP-608 Automated Permeameter-Porosimeter from Coretest systems, USA. The maximum confining pressure is 9000 psi and the measuring range of porosity and permeability are 0.1–40% and 0.001–10000 mD, respectively.

2.2.2. Experimental Methods

A schematic depiction of the CO₂ treatment apparatus used in this research is shown in Figure 3. The apparatus mainly consists of an ISCO pump, a pressure gauge, two intermediate containers and a vacuum pump. The experimental procedures of SEM and XRD analysis, before and after CO₂ treatment, are briefly described as follows. Firstly, the micromorphology and mineral composition of shale are measured through SEM and XRD analysis, respectively. Next, the samples and CO₂-saturated brine are put into a clean intermediate container for CO₂ treatment. The temperature and pressure of CO₂ treatment are set at 90 °C and 30 MPa. Finally, after 7 days of treatment, the samples are taken out and dried in an oven, and subsequently are subject to characterization of micromorphology and mineral composition to analyze the influences of CO₂ treatment.

The experimental procedures of porosity and permeability analysis before and after CO₂ treatment are briefly described as follows. Firstly, the porosity and permeability of shale are measured with a permeameter–porosimeter. Next, the core samples are put into a clean intermediate container and soaked in CO₂-saturated brine for the periods of 1 day, 3 days, 5 days or 7 days, after which they are dried and subjected to porosity and permeability analysis to analyze the influences of different CO₂ treatment times.

3. Results and Discussion

3.1. Lithofacies Analysis of Qingshankou Formation

The main lithofacial types of the Qingshankou Formation are identified through core observation and XRF analysis, and the results are shown in Figure 4. The shale in the Qingshankou Formation can be divided into three main lithofacial types: foliaceous shale, laminated feisic shale and laminated diamictic shale. These three main types of shale account for more than 90% of the Qingshankou formation and are the main target area for exploration and development.

The photo and XRF result of foliaceous shale sample are shown in Figure 4a,d. The foliaceous shale is mainly black and dark gray, with a fine texture, high oil saturation and low interlayer difference. Its element distribution is relatively uniform. The photo and XRF result of laminated feisic shale sample are shown in Figure 4b,e. The laminated feisic shale is mainly dark gray with relatively low oil saturation and significant interlayer difference. Its element distribution is uneven with many feisic laminas. The thickness of these laminas is about 1 mm and their composition is mainly silica and iron elements, indicating a rapid alternative change of highly organic shale and lowly organic silty laminas. The photo and XRF result of laminated diamictic shale sample are shown in Figure 4c,f. The laminated diamictic shale is mainly dark gray with relatively low oil saturation and significant interlayer difference. Its element distribution is uneven, with many diamictic laminas. The thickness of these laminas is about 1 mm and their compositions are mainly silica, iron and calcium elements, indicating a rapid alternative change from highly organic shale to lowly organic silty and carbonate laminas.

The average mineral composition of these three main types of shale is shown in Figure 5. The results show that the main minerals of foliaceous shale are clay minerals, quartz and feldspar. Clay minerals account for more than half of the total mineral content, and the proportions of quartz and feldspar are 27.4% and 10.8%, respectively. The proportions of carbonate and other minerals are very low, only 5.3% and 3.3%, respectively. For laminated feisic shale, quartz and feldspar together account for about half of the total minerals and are greater than the proportion of clay minerals, which is 41.9%. The proportion of carbonate and other minerals is very low, less than 5%. For laminated diamictic shale, quartz and feldspar together account for 41.6% of the total minerals and are greater in proportion than that of clay minerals, which is 40.3%. The proportion of carbonate minerals is relatively high and accounts for more than 15% of the total content. Obviously, there are significant differences in the mineral composition among these three main types of shale samples.

Due to the significant differences of mineral composition, varied micromorphologies and pore structures are observed during SEM analysis and the results are shown in Figure 6. As shown in Figure 6a,b, after mechanical and argon ion polishing, the micromorphologies of foliaceous shale samples are smooth, flat and tight. There are some micropores, the sizes of which are less than 5 μm. The main reservoir spaces are micro fractures, intergranular pores and organic pores. The number and size of these pores are relatively many and large, with some natural microfractures. As a result, the connectivity between pores and fractures maybe good, which may form seepage networks for shale oil. The micromorphology of laminated feisic shale is tighter than foliaceous shale and has only a few micropores, the sizes of which are less than 3 μm. The main reservoir spaces are intergranular pores, granular dissolved pores and intergranular fractures. The number and size of these pores are fewer and smaller, with few natural microfractures. As a result, the connectivity between pores and fractures is poor, and it is difficult for shale oil to flow. The micromorphology of laminated diamictic shale is tightest among the three types of shale, and there are hardly any micropores. The main reservoir spaces are intergranular pores, granular dissolved pores and intergranular fractures. Due to diagenetic cementation, the number and sizes of these pores and fractures are few and small. As a result, the connectivity between pores and fractures is least, through which it is difficult for shale oil to flow. In addition, there are many biogenic calcium carbonate minerals that cannot be observed in other samples. The differences in micromorphologies and pore structures may affect the results of the CO₂ treatment.

3.2. Micromorphology Analysis on Different Lithofacial Types of Shale during CO₂ Treatment

In order to explore the effect of CO₂ treatment on the micromorphologies of different lithofacial types of shale, SEM analysis is carried out and the results are shown in Figure 7. The original pore structures and micromorphologies of foliaceous shale are shown in Figure 7a. After mechanical and argon ion polishing, the surfaces of the shale samples become smooth and tight, without mineral migration. There are a few small primary pores, and the pore connectivity is poor. After CO₂ treatment, the CO₂–water–rock reaction significantly affects the surface structures of the shale samples, and many new dissolution pores are generated, as shown in Figure 7d. According to the XRD analysis, the main minerals of the shale samples are albite, potash feldspar, calcite, dolomite and chlorite, and the probable interaction mechanism during CO₂ treatment is shown as follows:

2NaAlSi₃O₈ + 2CO₂ + 3H₂O → 2Na⁺ + 2HCO₃⁻ + 4SiO₂ + Al₂Si₂O₅(OH)₄

(1)

2KAlSi₃O₈ + 2H⁺ + 9H₂O → 2K⁺ + 4H₄SiO₄ + Al₂Si₂O₅(OH)₄

(2)

CaCO₃ + H⁺→Ca²⁺ + HCO₃⁻

(3)

CaMg(CO₃)₂ + 2H⁺ → Ca²⁺ + Mg²⁺ + 2HCO₃⁻

(4)

[Fe/Mg]₅Al₂Si₃O₁₀(OH)₈ + 5CaCO₃+5CO₂ → 5Ca[Fe/Mg](CO₃)₂ +
Al₂Si₂O₅(OH)₄ + SiO₂ + 2H₂O

(5)

Due to the small size and scattered distribution of mineral particles, the sizes of new dissolution pores are small and the improvement in pore connectivity is poor. Meanwhile, CO₂ treatment results in some new mineral precipitation and migration by geochemical reactions. Both the precipitation and migration of minerals block pores and throats and reduce the porosity and pore connectivity of shale samples, leading to a decrease in permeability.

The original pore structures and micromorphologies of laminated feisic shale are shown in Figure 7b. The surfaces of the shale samples are smooth and tight, without mineral migration. There are a few small primary pores, and the pore connectivity is poor. After CO₂ treatment, the CO₂–water–rock reaction significantly leads to many new dissolution pores, as shown in Figure 7e. In certain areas, rich in albite, potash feldspar, calcite and so forth, large-scale dissolution of these minerals occurs and results in many large-sized pores. Due to the large sizes of mineral particles in laminas, the sizes of new dissolution pores can reach 10–30 μm in diameter. Although the precipitation and migration of minerals caused by CO₂ treatment partially block pores and throats, the porosity and pore connectivity of the shale samples is still improved significantly under the existence of large-sized dissolution pores, leading to an increase in permeability.

The original pore structures and micromorphologies of laminated diamictic shale are shown in Figure 7c. The surface of the shale samples becomes smooth and tight, without mineral migration. Due to the fine diagenetic cementation, there are hardly any micropores, and the pore connectivity is poor. After CO₂ treatment, the CO₂–water–rock reaction significantly leads to many new dissolution pores, as shown in Figure 7f. There is a large-scale dissolution of some minerals, such as albite, potash feldspar, calcite and so forth. Due to the large sizes of mineral particles in laminas, the sizes of new dissolution pores can reach 50 μm in diameter. Furthermore, the dissolution of biogenic calcium carbonate minerals results in many dissolution microfractures, which can significantly improve the porosity and pore connectivity of shale and increase the flowability of shale oil. Although the precipitation and migration of minerals caused by CO₂ treatment partially block pores and throats, the porosity and pore connectivity of the shale samples is still improved significantly by the presence of large-sized dissolution pores and fractures. So, after CO₂ treatment, the permeability of shale samples can be improved significantly.

3.3. Mineral Composition Analysis of Different Lithofacial Types of Shale during CO₂ Treatment

In order to explore the effect of CO₂ treatment on the mineral compositions of different lithofacial types of shale, XRD analysis is carried out before and after CO₂ treatment, and the results are shown in

Table 2. Mineral composition analysis of shale samples.

Lithofacies	Treatment	Mineral Composition (%)
		Quartz	Feldspar	Clay	Carbonate	Other
foliaceous shale	untreated	26.6	11.2	52.9	6.1	3.2
	CO2 treated	34.3	6.8	50.2	3.3	5.4
laminated felsic shale	untreated	31.1	19.3	40.6	4.1	4.9
	CO2 treated	39.3	12.1	38.9	2.1	7.6
laminated diamictic shale	untreated	28.1	10.8	41.2	16.3	4.6
	CO2 treated	37.1	5.6	43.2	7.2	6.9

. Although there are significant differences in mineral composition among these three main types of shale samples, the change rules of mineral composition are similar between them. Compared with the samples without CO₂ treatment, the proportion of feldspar and carbonate minerals of the treated samples decreases by 4.4–7.2% and 2.8–9.1%, respectively. In combination with SEM analysis, it is revealed that happens because of the dissolution of feldspar and carbonate minerals in the CO₂ treatment. Quartz does not react with CO₂ and the increase in its content is caused by the decrease in the overall quality of the shale samples. Meanwhile, as shown in Formulas 1 and 5, albite and chlorite react with CO₂ to create quartz. As a result, the proportion of quartz increases obviously after CO₂ treatment.

3.4. Porosity and Permeability Analysis of Different Lithofacial Types of Shale during CO₂ Treatment

In order to explore the effects of CO₂ treatment on the porosity and permeability of different lithofacial types of shale, core soaking experiments are carried out. The physical properties of the shale core samples are listed in

Table 3. Physical properties of shale cores.

Sample	Diameter (cm)	Length (cm)	Porosity (%)	Permeability (mD)
Q1	2.50	5.02	8.11	0.0572
Q2	2.51	5.01	7.29	0.0443
Q3	2.51	4.99	6.17	0.0628
Q4	2.50	5.02	5.42	0.0767
Q5	2.52	5.01	5.77	0.0417
Q6	2.51	5.00	4.56	0.0421

. Sample Q1 and Q2 are obtained from foliaceous shale formation. Sample Q3 and Q4 are obtained from laminated felsic shale formation. Sample Q5 and Q6 are obtained from laminated diamictic shale formation. As shown in Table 3, the porosities of core samples are extremely low and only 4.56–8.11% under confining pressure conditions. The porosity of foliaceous shale is the highest and the laminated felsic shale ranks the second, which is consistent with the SEM results above. Furthermore, the connectivity of shale is poor, and the permeability of core samples is extremely low and only 0.0417–0.0767 mD, making it difficult for shale oil to flow.

The results of porosity and permeability after CO₂ treatment are shown in Figure 8 and Figure 9, and there are significant differences in the change rules for porosity and permeability among the three main types of shale. For foliaceous shale, CO₂ treatment has both improving and damaging effects on porosity and permeability. With the increasing treatment time, the porosity and permeability of Q1 sample show a fluctuating, upward trend. After 7 days’ treatment, the porosity and permeability of the Q1 sample increase by 8.14% and 62.93%, respectively. Meanwhile, with the increasing treatment time, the porosity and permeability of the Q2 sample decline noticeably. After 7 days’ treatment, the porosity and permeability of the Q2 sample decrease by 13.17% and 63.43%, respectively. In combination with SEM analysis, it is revealed that there are many new, small dissolution pores, and precipitation and migration of minerals occur after CO₂ treatment. When the dissolution effect dominates, CO₂ treatment can improve porosity and permeability significantly (Q1). When the precipitation and migration effects dominate, CO₂ treatment shows a damaging effect on porosity and permeability (Q2). Therefore, serious consideration should be given to potential reservoir damage when CO₂ is injected into foliaceous shale formations.

For laminated felsic shale, both porosity and permeability improve significantly after CO₂ treatment. After 7 days’ treatment, the porosities of the Q3 and Q4 samples increase by 12.48% and 18.27%, and their permeability increases by 93.31% and 174.97%, both respectively. In combination with SEM analysis, there are many large-sized mineral particles in felsic laminas, such as albite, potash feldspar, calcite and so forth. After CO₂ treatment, the large-scale dissolution of these minerals occurs and results in many large-sized pores, and the sizes of new dissolution pores can reach 10–30 μm in diameter. Although the precipitation and migration of minerals caused by CO₂ treatment can partially block pores and throats, the large-scale dissolution effect dominates the change rule, leading to an increase in porosity and permeability. Therefore, it might be better to apply CO₂ technology for enhancing oil recovery when the target formation mainly consists of laminated felsic shale.

For laminated diamictic shale, both porosity and permeability improve significantly after CO₂ treatment. After 7 days’ treatment, the porosities of the Q5 and Q6 samples increase by 17.68% and 24.78%, and their permeability increases by 412.47% and 872.21%, both respectively. In combination with SEM analysis, besides large-sized feldspar particles, there are many biogenic calcium carbonate minerals. The dissolution effect results in many dissolution pores and dissolution microfractures, which can significantly improve the porosity and pore connectivity of shale. Although the precipitation and migration of minerals caused by CO₂ treatment can partially block pores and throats, the existence of dissolution pores and fractures dominates the change rule, leading to a dramatic increase in porosity and permeability. When the target formation mainly consists of laminated diamictic shale, the application of CO₂ technology is recommended. Through the mechanisms of miscible flooding, viscosity reduction, formation energy supplements and improvement in porosity and permeability, CO₂ technology can effectively enhance shale oil recovery.

4. Conclusions

In this research, the effects of CO₂ treatment on different lithofacial types of shale have been systematically studied through core observation and XRF analysis, mineral composition analysis, micromorphology analysis and core soaking experiments. The conclusions are as follows:

The shale in the Qingshankou Formation can be divided into three main lithofacial types: foliaceous shale, laminated feisic shale and laminated diamictic shale. These three main types of shale account for more than 90% of the Qingshankou formation and are the main target area in exploration and development thereof. There are significant differences in micromorphologies and pore structures between them. There are relatively more pores with some natural microfractures in foliaceous shale, a few micropores in laminated feisic shale and hardly any micropores in laminated diamictic shale.

After CO₂ treatment, there are significant differences between the changes in micromorphologies and pore structures among the three main types of shale. For foliaceous shale, many new, small dissolution pores are generated, accompanied by the precipitation and migration of minerals. For laminated feisic shale, large-scale dissolution occurs and results in many large-sized pores (10–30 μm in diameter), which improves the porosity and pore connectivity of the shale samples. For laminated diamictic shale, the dissolution of biogenic calcium carbonate minerals results in many large dissolution pores and dissolution fractures, which greatly improve the porosity and pore connectivity of the shale samples.

Under the effects of mineral composition and micromorphology, CO₂ treatment has both improving and damaging effects on porosity and permeability for foliaceous shale. When the target formation mainly consists of foliaceous shale, serious consideration should be given to CO₂ technology to prevent potential reservoir damage. Meanwhile, for laminated feisic shale and laminated diamictic shale, both porosity and permeability improve significantly after CO₂ treatment. When the target formation mainly consists of laminated shale, the application of CO₂ technology is recommended.