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Article

Controlling the Hydro-Swelling of Smectite Clay Minerals by Fe(III) Reducing Bacteria for Enhanced Oil Recovery from Low-Permeability Reservoirs

by
Kai Cui
1,
Chengjun Wang
2,
Li Li
3,
Jungang Zou
3,
Weihong Huang
3,
Zhongzhi Zhang
4,
Heming Wang
4,* and
Kun Guo
1,*
1
School of Chemical Engineering and Technology, Xi’an Jiaotong University, Xi’an 710049, China
2
College of Chemistry and Chemical Engineering, Xi’an Shiyou University, Xi’an 710065, China
3
The First Oil Production Plant of Xinjiang Oilfield Company, China National Petroleum Corporation, Xinjiang 834000, China
4
State Key Laboratory of Heavy Oil Processing, Beijing Key Lab of Oil & Gas Pollution Control, College of Chemical Engineering and Environment, China University of Petroleum, Beijing 102249, China
*
Authors to whom correspondence should be addressed.
Energies 2022, 15(12), 4393; https://doi.org/10.3390/en15124393
Submission received: 11 May 2022 / Revised: 13 June 2022 / Accepted: 14 June 2022 / Published: 16 June 2022
(This article belongs to the Special Issue Unconventional Oil & Gas Reservoir Seepage and Enhanced Oil Recovery)
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Abstract

:
The hydro-swelling of smectite clay minerals in low-permeability reservoirs further decreases the reservoir permeability and results in low oil recovery. Currently, the traditional chemical anti-swelling agents are widely used, but most of them are only effective in the short term and are not environmentally friendly. Here, we report the use of Fe(III) reducing microorganisms (FeRM) as a novel green anti-swelling agent to enhance oil recovery from low-permeability reservoirs. The results showed that FeRM (Proteus hauserifective) inhibited/reduced the hydro-swelling of smectite clay minerals through a three-step biochemical mineralization reaction process. The structural Fe(III) reduction in minerals by FeRM can be an important driving force for illitization. The maximum inhibition efficiency (36.6%) and shrinkage efficiency (69.3%) were achieved at 35 °C and 0.1 Mpa. Furthermore, core displacement tests showed that FeRM reduced the waterflooding injection pressure by 61.1%, increased the core permeability by 49.6%, and increased the oil recovery by 8.1%. Finally, the mechanism of FeRM-enhanced oil recovery was revealed. This study demonstrates that using FeRM to inhibit/reduce the hydro-swelling of clay minerals holds great potential to enhance the oil recovery from low-permeability reservoirs.

1. Introduction

With the depletion of high-quality oil reservoirs worldwide, the demand for oil production from low-permeability reservoirs is ever-increasing [1,2]. Petroleum production from low-permeability reservoirs is a huge challenge because conventional recovery techniques are inefficient [3]. Currently, there are many methods for increasing oil production. Among the improved oil recovery techniques, waterflooding with different concentrations can improve the production rate. However, this technique has the problem of scaling, for the prevention of which the inhibitor injection should be completed. This issue was evaluated by various authors [4,5]. Thus, enhanced oil recovery methods, especially in the low-permeability reservoirs, can be used to effectively develop the reservoirs. Nevertheless, the low-permeability reservoirs mainly contain smectite, illite, mixed smectite/illite, chlorite, and other irregular clay minerals [6]. Waterflooding could cause clay minerals such as smectite and smectite/illite mixed-layer minerals to expand (hydro-swelling volume up to 600~1000%) [7]. The hydration swelling of smectite and smectite/illite mixed-layer minerals dramatically reduces the reservoir’s porosity and permeability, which mainly leads to high injection pressure and low oil recovery [8]. Therefore, inhibiting the hydro-swelling of clay minerals is an effective way to enhance the oil recovery from the low-permeability reservoirs.
Currently, chemical anti-swelling agents, such as inorganic salts (KCl and NaCl), organic amine compounds, quaternary ammonium Gemini cationic surfactants, polymers, and polyglycerols [9,10,11], are commonly spiked in the flooding fluids to inhibit clay hydro-swelling and reduce the injection pressure. However, the clay minerals are composed of a stack of negatively charged silicate layers separated by interlayer cations (such as Na+, K+, Ca2+, and Mg2+, etc.) [12]. In this case, the certain disadvantages associated with these inorganic ions, such as toxicity, incompatibility with the anionic drilling fluid additives, and flocculation of solids, limit their application in the field [13]. Moreover, there are also some concerns and drawbacks regarding these chemical anti-swelling agents, such as the large dosage, high price, and poor long-term efficacy [14]. Moreover, these chemical agents also would cause permanent damage to reservoirs and induce adverse effects on the environment [15]. Consequently, there is an urgent need to develop green, low-cost, and effective anti-swelling agents.
In recent years, microbial-enhanced oil recovery, which employs microorganisms to facilitate and increase oil production from the reservoirs, has become a popular tertiary production technology. Previous studies mainly focus on the influence of microbial metabolic activities on the wettability of rock surfaces and the physicochemical properties of crude oil [16,17]. There are limited reports on the interactions between microorganisms and clay minerals in low-permeability reservoirs for enhanced oil recovery. However, microbial and mineral interactions hold great potential for material circulation on Earth, serving as a bridge between the lithosphere and life [18]; for example, the formation process of the oil reservoir has always been accompanied by the interaction between microorganisms and clay minerals. The physical and chemical properties of clay minerals are largely controlled by the action of bio-mineralization [19]. In response, the changes in these mineral properties also affect the pore structure and permeability of the reservoir, and the formation process, quantity, spatial distribution, and the re-migration and enrichment of the remaining oil [16,20].
The clay mineral transformation is one of the most important diagenetic processes in the oil reservoir, which has long been considered to only happen at high temperatures (300~350 °C) and high pressure (100 MPa), with a long reaction time (4~5 months). Nevertheless, it has been reported that microorganisms could interact with clay minerals and impact the clay minerals’ physicochemical properties, such as layer charge, dilatancy, and specific surface area [17]. For instance, Kim et al. found that the dissimilatory Fe(III) reducing microorganisms (FeRM) could induce the conversion of smectite to a less swellable mineral, smectite [21]. Our group recently reported that FeRM could also facilitate the transformation of smectite to illite, thereby efficiently inhibiting minerals’ swelling [20]. With the help of FeRM, the reaction of smectite–illite took place within 14 days at room temperature and pressure. These findings challenge the long-held understanding that the smectite–illite transformation process is controlled by temperature, pressure, and time. Since Fe(III)-containing clay minerals are widely present in the low-permeability reservoirs, FeRM has been proposed as anation potential anti-swelling agent for enhanced oil recovery. However, the effectiveness of using FeRM to enhance oil recovery from low-permeability reservoirs has not been tested yet.
The purpose of this study is to explore the biochemical process of controlling hydro-swelling by FeRM in low-permeability reservoirs and explain the mechanism of FeRM-driven enhanced oil recovery. Using synthetic cores containing smectite to simulate the low-permeability reservoirs, the effectiveness of FeRM on the inhibition of smectite clay minerals’ hydro-swelling was examined. In addition, core displacement tests were conducted to evaluate the EOR efficiency. Finally, the distribution and structure of core pore-throats were characterized to understand the mechanism of hydro-swelling reduction and oil recovery enhancement. This study provides a theoretical basis for the inhibition and reduction of clay minerals’ hydro-swelling by FeRM in the oil fields and offers a novel technique for enhanced oil recovery in low-permeability reservoirs.

2. Materials and Methods

2.1. Fabrication of the Synthetic Cores

To simulate the hydro-swelling effect of the rocks in low-permeability reservoirs, six comparable synthetic sandstone cores were produced by adding 7–8% smectite clay minerals. The mineral particle size was less than 0.31 mm. The chemical composition of the smectite clay minerals was (Ca0.19Na0.17K0.08)0.44(Al1.36Mg0.32Fe0.26)1.94(Si3.87Al0.13)4.0O10(OH)2.0·nH2O, with the total Fe content of 3.7% [21]. The cores were cleaned with toluene vapor by Soxhlet extraction and then washed with deionized water to remove impurities. Finally, the cores were dried at 60 °C in a vacuum drying oven. Each core had a gas permeability range of 30–40 mD. To simulate the low-permeability reservoir conditions, core samples with water permeability of 1–5 mD were selected as experimental cores. In addition, the production of synthetic core samples was commissioned by the China University of Petroleum (Beijing), and the preparation process was kept confidential. In this study, we only purchased the synthetic core samples and then measured the gas permeability and water permeability of the core samples by using the nitrogen and waterflooding fluid as measuring media according to the industry standard SY/T5336-2006 “Core Analysis Method”, respectively [22]. The properties of the six cores are shown in Table 1.

2.2. Preparation of the Flooding Fluids

Waterflooding fluid: The produced water was collected from a production well in Changqing oilfield (Xi’an, China). The characteristics of the produced water and the ionic composition of the injection fluid are summarized in Tables S1 and S2. The produced water was sterilized to remove microorganisms and then used as the waterflooding fluid.
Microbial flooding fluids: The FeRM was isolated from the produced water of Changqing oilfield in China, which exhibits a similarity of 98–99% to Proteus hauseri (accession number NCBI: OSB73291.1). To activate the preserved strain, 2.0 mL of the FeRM preservation solution was added to 100 mL of LB medium (peptone 10 g/L, yeast powder 10 g/L, and NaCl 10 g/L) for cultivation at 35 °C for 24 h. Then, 5.0 mL of the activated FeRM was inoculated into 100 mL of inorganic salt medium (sucrose 2 g/L, NaNO3 10 g/L, NaMo4 0.08 g/L, KH2PO4 1.0 g/L, (NH4)3HPO4 1.1 g/L, and MgSO4 0.2 g/L) for enrichment at 35 °C. When the concentration of FeRM reached 106–107 cells/mL, the bacteria solution was added to sterilized produced water (5.0% v/v or 7% v/v) to prepare the microbial flooding fluids. In addition, according to the reservoir source and screening conditions of FeRM, we preliminarily determined the experimental temperature (30–40 °C) and pressure (0.1–2.0 MPa) in this study.

2.3. Inhibiting and Reducing the Hydro-Swelling of Smectite Clay Minerals

The impact of FeRM on controlling the smectite clay minerals’ hydro-swelling was evaluated by a clay dilatometer (PCY, Xiangtan Xiangyi Instrument Co., Ltd., Xiangtan, China). Before usage, the core plugs were cut into 2.0 cm pieces and dried at 60 °C in a vacuum drying oven. After loading the core plugs into the dilatometer, nitrogen was then injected into the container to simulate the anaerobic condition of a low-permeability reservoir. When the temperature and pressure reached the setting value, the flooding fluid (50 mL at 10 mL/min) was added from the feeding port to start the tests. The tests were ended when the swelling height stopped changing. For the control group, the flooding fluid was the produced water after sterilization, and the testing conditions were 35 °C and 0.1 Mpa. For the experimental group, microbial flooding fluid was used, and different temperatures (30 °C, 35 °C, and 40 °C at 0.1 Mpa) and pressures (0.1 Mpa, 1.0 Mpa, and 2.0 Mpa at 35 °C) were investigated. The swelling height was recorded every minute to plot the swelling curves. Additionally, the size distribution of the smectite clay mineral particles before and after FeRM treatment was analyzed by a laser particle size analyzer (LS-POP, Ogilvy Instrument Co., Ltd., Zhuhai, China). The swelling efficiency (Y, %), inhibition efficiency ( Y 1 , %), and shrinkage efficiency ( Y 2 , %) were calculated by the following formulas:
Y = L 3 − L 2 L 1 − L 0 × 100 %
Y 1 = 1 − Y
Y 2 = L 3 − L 4 L 3 − L 2 × 100 %
where L 0 (µm) was the initial height in the control group; L 1 (µm) was the final swelling height in the control group; L 2 (µm) was the initial height in the experimental group; L 3 (µm) was the maximum swelling height in the experimental group; L 4 (µm) was the final swelling height in the experimental group.

2.4. Core Displacement Tests to Evaluate the EOR

A schematic of the experimental setup is illustrated in Figure 1. A real photo of the core displacement apparatus device is shown in Figure S1 in the Supplementary Materials. Before the core displacement tests, cores (#1, #2, and #3) were aged with sterilized crude oil (collected from Changqing oilfield, density 0.894 g/cm3, viscosity 18 mPa·s at 35 °C). To simulate the conditions of Changqing’s low-permeability oilfield, the oil saturation efficiencies of the aged core plugs were around 55–65%. The operating range of the waterflooding process is salinity less than 100,000 mg/L, permeability between 1 and 50 mD, and water cut is greater than 50–60%. Among them, core #1 was used as a blank control group without waterflooding. Both the waterflooding (core #2, without FeRM) and FeRM flooding (core #3, 5.0% of FeRM) were conducted to recover oil. The temperature was controlled at 35 °C. The experimental design is shown in Table 2.
The specific operation steps are as follows. (1) The aging cores (#2 and #3) were inserted into the primary waterflooding experimental group, respectively, and the oil displacement rate was set at 0.2 mL/min. The injection time was 4 to 5 h and until the oil production became negligible. The discharged volumes of oil and produced water were measured by an oil–water separation meter. The point interval of measurement was 0.1 pore volume (PV). (2) When the water content was greater than 60%, the FeRM flooding fluid was injected into core #3 by the alternating slug method with an injection volume of 1.0 PV at 0.5–1.0 h. For the experimental control group (core #2), the flooding fluid was the produced water after sterilization. (3) The ends of the core holder were closed and then incubated at 35 °C for 30 days. (4) When the incubation ended, waterflooding was resumed immediately until the water content was greater than 98% or the accumulation of flooding reached 5.0 PV. The experiment was then stopped. When displacement tests ended, the volumes of produced oil and water were measured by the calibration oil–water separator. The oil recovery efficiency ( η 1 ,%) was calculated by the following formulas:
η 1 = ( V d / V 0 ) × 100 %
where V d (mL) was the cumulative oil output after displacement; V 0 (mL) was the saturated oil in the core before displacement.
During the entirety of the displacement tests, the pressures of different flooding fluids injections were recorded, and the reduction efficiency ( η , %) of water displacement pressure was calculated as follows:
η = P 0 − P 1 P 0 × 100 %
where P 0 (Mpa) was the primary waterflooding fluid injection pressure before FeRM action;   P 1 (Mpa) was the secondary waterflooding fluid injection pressure after FeRM action.

2.5. Analysis of Core Characteristic Parameters after Displacement Tests

Core permeability test: The cores were washed to remove residual crude oil and dried at 105 °C when core displacement tests ended. According to the industry standard SY/T5336-2006 “Core Analysis Method” [22], the gas permeability of cores was measured by using nitrogen as measuring media. The enhanced permeability efficiency ( η 2 , %) was calculated by the following formula:
η 2 = P e 2 − P e 1 P e 0 − P e 1 × 100 %
where P e 0 (mD) was the initial gas permeability of the core before displacement;   P e 1 (mD) was the gas permeability of core hydro-swelling before displacement;   P e 2 (mD) was the gas permeability of the core after displacement.
Core pore-throat structure test: When the core permeability tests ended, according to the industry standard SY/T5336-2006 “Core Analysis Method”, the pore-throat size, capillary pressure, and structure distribution of cores were measured by the constant rate of mercury intrusion porosimetry [23].

3. Results

3.1. The Impact of FeRM on the Hydro-Swelling Properties of Core Plugs

The growth of microorganisms and the hydro-swelling properties of clay minerals are subjected to different influences with the changes in reservoir temperature and pressure in low-permeability reservoirs [24]. To test the effectiveness of FeRM on the hydro-swelling reduction of smectite clay minerals, core plug hydro-swelling tests were conducted with water flooding (control) and FeRM flooding (experiment) at 35 °C and 0.1 Mpa. The hydro-swelling properties of core plugs are shown in Figure 2. In the control group, the swelling height quickly increased to 470 µm within 60 h, and then the swelling height tended to be constant (Figure 2a). Accordingly, the maximum swelling efficiency was 36.8%. In the experimental group, it took 96 h for the swelling height and efficiency to reach their maximum values (298 µm and 23.4%) (Figure 2b). Moreover, the swelling height of the core plug with FeRM started to decrease after 140 h and gradually stabilized around 91 µm after 240 h. Accordingly, the final swelling efficiency decreased to 7.5%. In addition, the physical hydro-swelling properties of smectite clay minerals after FeRM action were compared with those of other anti-swelling agents (KCl, 5%) by static experiments, and we found that FeRM showed a better ability to inhibit the hydro-swelling of clay minerals (increasing efficiency by 5%) (Figure S2).
These results demonstrated that FeRM could not only slow down the hydro-swelling rate but also dramatically shrink the swollen smectite clay minerals. Moreover, the biochemical processes of hydro-swelling reduction by FeRM could be divided into three phases (Figure 2b). Phase I was a rapid hydro-swelling period. In this period, the physical hydro-swelling properties of smectite clay minerals were the main factor influencing the swelling height. In phase II, FeRM bio-mineralization (namely smectite to illite) could be used for inhibiting or shrinking the swelling height. With the FeRM control, a dynamic equilibrium effect would be formed between the physical swelling of smectite clay minerals itself and the inhibition or shrinkage of hydro-swelling. In phase III, the swelling height may have reached its maximum. At the same time, FeRM accelerated the Fe(III) reduction and promoted the formation of illite. Consequently, these bio-mineralization behaviors induced the shrinkage of the swelled smectite clay minerals. The occurrence of the above phenomenon verified our previous research wherein FeRM could weaken the hydro-swelling property of smectite clay minerals by changing the mechanical and mineralogical characteristics of the minerals [20]. Moreover, the size distribution (<60 µm) of the mineral particles decreased before and after the FeRM treatment (Figure S3), indicating that FeRM changed the structure and properties of the smectite clay minerals themselves and their metabolites with the hydro-swelling of clay minerals, and further stabilized or prevented the migration of clay particles to clog the pore-throats.

3.2. The Impact of Temperature and Pressure on the Hydro-Swelling Reduction by FeRM

The growth of microorganisms and the hydro-swelling properties of clay minerals are subjected to changes with the changes in temperature and pressure in low-permeability reservoirs [25]. Hence, the effects of temperature and pressure on the hydro-swelling reduction of clay minerals by FeRM were investigated. To better demonstrate the inhibition and shrinkage ability of FeRM on core plugs, the inhibition efficiency and shrinkage efficiency were calculated (Figure 3) based on the results of the hydro-swelling experiment (Figure 2 and Figure S4).
At 0.1 Mpa, the inhibition efficiency at 35 °C was 36.6%, which was higher than that at 30 °C (25.4%) and 40 °C (28.4%) (Figure 3a). Meanwhile, the shrinkage efficiency at 35 °C (69.3%) was also superior to that at 30 °C (55.8%) and 40 °C (41.2%) (Figure 3b). This can be attributed to fact that the activity of FeRM is higher at 35 °C, which accelerated the capacity of cation exchange and smectite–Fe(III) reduction in the clay minerals [26]. It has also been documented that the microorganism, as an in situ reducing agent, participates in the redox cycles for structural Fe in clay minerals, and such interactions can be used for the illitization of smectite [27].
At 35 °C, when the pressure changed from 0.1 Mpa to 2.0 Mpa, the inhibition efficiency decreased with the increase in pressure, while the shrinkage efficiency first decreased and then increased with the rise in pressure (Figure 3c,d). Nevertheless, the best inhibition efficiency (36.6%) and shrinkage efficiency (69.3%) were both achieved at 0.1 Mpa. The decrease in the inhibition/shrinkage efficiencies may be attributed to the weakening of the water desorption capacity in the smectite clay mineral interlayers with the rising pressures [28]. The bioavailability of smectite–Fe(III) might change under high pressure (2.0 Mpa) due to the alteration of the water desorption capacity, and thus may influence FeRM’s inhibition efficiency. It has been demonstrated that a decreased osmotic swelling caused by higher pressure can lead to fewer edge sites for microbial attachment and subsequently a lower reduction extent [29].

3.3. Evaluation of FeRM-EOR

Core flooding experiments were used to test the oil recovery ability of FeRM flooding. The EOR results are shown in Figure 4. After the primary waterflooding, when the water content in cores #2 and #3 was greater than 60.0%, the oil recovery efficiencies were 20.9% and 24.6%, respectively. According to the literature [30], microorganisms have better growth and higher metabolic activities when the reservoir water content exceeds 60.0%. Subsequently, core #3 proceeded with the FeRM flooding by the injection method of alternating slug, while core #2 continued with the water flooding as the test control group. Then, 30 days of incubation was performed to ensure proper interaction between FeRM and smectite clay minerals in cores. After the secondary waterflooding, the final oil recovery efficiencies for core #2 and core #3 reached 45.7% and 53.8%, respectively. The results showed that the recovery of FeRM flooding was 8.1% higher than that of waterflooding. EOR may be attributed to the bio-mineralization behavior of FeRM, which effectively improved the distribution of oil and water in cores by inhibiting and reducing the hydro-swelling of clay minerals after the primary waterflooding. In conclusion, the results can be used as a reference for reservoirs (permeability range is 1–50 mD) whose porosity is different from the studied porosity, although there are some errors in using synthetic experimental cores to simulate the real reservoir cores. However, the experimental results can provide data guidance for the reservoirs.

3.4. Changes in Permeability and Waterflooding Injection Pressure

The waterflooding injection pressure and permeability in the low-permeability reservoirs reflect the ability of reservoir swept areas to affect the ratio, distribution, and migration of oil and water [31,32]. Thus, as a macroscopometric index for the effectiveness of the hydro-swelling reduction and injection augmentation of FeRM flooding, the waterflooding injection pressure and permeability in the core displacement tests were investigated and the results are shown in Figure 5. The permeability value of the untreated core was 36.4 mD. After waterflooding, the permeability value of core #2 dramatically reduced to 14.7 mD as a result of the smectite clay minerals’ hydro-swelling. In comparison, after FeRM flooding, the permeability value of core #3 was 35.2 mD, and the permeability increased by 49.6%. Meanwhile, the waterflooding injection pressure value in core #3 (0.35 MPa) was significantly decreased compared with core #2 (0.90 MPa), and the reduction efficiency was 61.1%. These results confirmed that FeRM could effectively increase the permeability and reduce the waterflooding injection pressure through bio-mineralization. On the other hand, the conversion from S-I by FeRM action could cause dehydration or the loss of the water present between the layers of the smectite, along with the water adsorbed on the surface of the clay minerals, resulting in a decrease in fluid pressure [33]. Meanwhile, this smectite illitization, associated with inhibition, shrinkage, and dissolution, caused pore types to become connected, thus increasing permeability during this process. Furthermore, illite and mixed-layer I-S recrystallization and neomorphism generated or enlarged pore spaces as a result of an increase in crystal size [34].

3.5. Changes in Distribution and Structure of Core Pore-Throats

To investigate the effects of water/FeRM flooding on the distribution and structure of core pore-throats, mercury intrusion porosimetry of the cores (#1, #2, and #3) was conducted. The pore-throat size distribution curves are presented in Figure S5, and the data of the pore-throat parameters are shown in Table 3. The pore-throat coefficient and average pore-throat radius of core #1 in the control group before hydro-swelling were 6.28 and 12.853 μm, respectively. Meanwhile, when the capillary pressure value was 0.074 Mpa (Figure S5a), the mercury saturation frequency and saturation at 10.0 μm were 27.7% and 57.8%, respectively. After the waterflooding, the pore-throat coefficient (5.82) and the average pore-throat radius (9.113 μm) of core #2 decreased dramatically compared with core #1. These results indicated that the connectivity and radius of pore-throats were reduced with the hydro-swelling of the smectite clay minerals.
The mercury saturation frequency (35.7%) decreased significantly at 10.0 μm and 0.074 Mpa (Figure S5b), while the mercury saturation (53.6%) increased. The above case might be ascribed to the micropore-throat blocking effects of hydro-swelling smectite clay minerals [35]. This clogging behavior further resulted in poor connectivity of the pore network and increased mercury infiltration resistance considerably. By contrast, after the FeRM flooding, the pore-throat coefficient of core #3 increased by 0.67, and the average pore-throat radius increased by 2.852 μm. The decrease in mercury saturation frequency (30.6%) was most significant compared with core #2 and the increase in mercury saturation (54.1%) (Figure S5c). The results demonstrated that FeRM could effectively widen the pore-throat radius and improve pore-throat connectivity by inhibiting or reducing the smectite clay minerals’ hydro-swelling.
To further analyze the characteristics of the distribution and structure of core pore-throats, the percentage of pore-throat radius ranges was investigated (Table 2). According to the literature [36], the micropore-throats (<0.01 μm) and mesopore-throats (0.01~0.05 μm) were the main types of pore-throats in all core samples (cores #1, #2, and #3). For the blank control group (core #1), the percentage of micropore-throats represented ~40.88% of the whole pore-throat structure, while the mesopore-throats accounted for 44.50%. The proportion of the macropore-throats was only 14.62%. After the waterflooding, in core #2, the percentage of micropore-throats (49.95%) significantly increased, while mesopore-throats (37.98%) and macropore-throats (12.07%) decreased with the smectite clay minerals’ hydro-swelling. Meanwhile, compared to core #1, 50% of the pore-throat radius decreased by 1.653 μm. Nevertheless, after the FeRM flooding, the percentage of mesopore-throats in core #3 increased by 4.50%. This phenomenon might have resulted from the combination of several micropores to form a mesopore. These results also confirmed that the hydro-swelling of clay minerals does affect the development and distribution of pore-throats. On the other hand, the development of pore-throats was controlled by the conversion of smectite to illite under the action of FeRM. The mesopores’ volume and surface areas will increase with the smectite layers converting into illite [20,33].

3.6. The Proposed Mechanism of FeRM-EOR

The hydro-swelling impact between smectite and its mixed minerals in low-permeability reservoirs is a bottleneck problem that directly leads to a decrease in reservoir porosity, permeability, and oil recovery. As illustrated in Figure 6, when smectite clay minerals are in contact with the formation of water, water molecules can be directly adsorbed or indirectly adsorbed by exchangeable cations, which makes the clay lamellar structure negatively charged [34]. Then, due to the electrostatic repulsion between clay sheets, the sheets begin to separate, resulting in the macroscopic manifestation of the increase in clay volume [37]. For these reasons, in our study, the pore-throat size became smaller to greatly decrease the permeability until the pore-throats were blocked.
To solve the above problem, smectite illitization has improved the reservoir properties by increasing the pore-throat size and improving the flooding flow capacity under the action of FeRM. Since the bioreduction of Fe(III) in smectite clay minerals can induce and lead to the smectite illitization reaction [20], the cation exchange capacity of the smectite clay minerals increases with the reduction of smectite–Fe(III) [37]. Then, the hydro-swelling capacity reduction will increase the hydrophobicity of the smectite minerals and thus prevent their swelling. On the other hand, both octahedral and tetrahedral sheets of smectite minerals can be dissolved by FeRM metabolites [38]. Under this circumstance, the interlayer water of smectite minerals is released, and the phase transformation to illite occurs. Additionally, structural Fe(III) in the octahedral sheet of smectite is reduced to Fe(II) by FeRM’s action, which may influence the net negative charge in the smectite mineral structure. Simultaneously, the cation exchange capacity (Na+, K+, and Ca2+, etc.) [12], specific surface area, layer charge, and swelling pressure will also change [39]. Finally, the smectite (crystal size of 145 nm) to illite (crystal size of 103 nm) transformation could result in the swelling volume of smectite minerals shrinking [20]. Therefore, the unit layer structural defects, interlayer exchangeable cation, and surface defects are the factors controlling the smectite clay minerals’ hydro-swelling by FeRM [40].
To sum up, the mechanism of FeRM-EOR in the low-permeability reservoirs could be proposed as follows. Firstly, FeRM improves the physical structure, crystalline state, and hydro-swelling properties of smectite or mixed-layer clay minerals [20,33]. Secondly, FeRM further inhibits/shrinks the smectite clay minerals’ hydro-swelling and prevents the migration of mineral particles to clog the pore-throats to enhance permeability. Finally, FeRM improves the reservoir seepage, reduces displacement fluids’ resistance, reduces the waterflooding injection pressure of oil wells, and enhances oil recovery.

4. Conclusions

MEOR technology will gradually become a new research concept in the oil recovery field. A green and in-situ FeRM-EOR technology that allows the inhibition and shrinkage of the hydro-swelling of smectite clay minerals in reservoirs is expected to fundamentally solve these bottleneck problems. This study developed a novel technique for EOR from low-permeability reservoirs by FeRM. The results showed that FeRM could inhibit and shrink the hydro-swelling of smectite clay minerals in core plugs. The biochemical process of inhibiting and shrinking the hydro-swelling of smectite clay minerals in the cores could be divided into three stages. The optimal operation conditions for the FeRM were 35 °C and 0.1 Mpa, and the inhibition and shrinkage efficiency of core plug hydro-swelling were 36.6% and 46.2%, respectively. Moreover, the physical hydro-swelling properties of the smectite clay minerals after FeRM action were compared with those of other anti-swelling agents (KCl) and we found that FeRM showed a better ability to inhibit the hydro-swelling of clay minerals. Moreover, FeRM could effectively reduce the waterflooding injection pressure (61.1%) and increase the core permeability (49.6%). Additionally, the core flooding experimental results showed that 5.0% of FeRM fluid injection resulted in an 8.1% enhancement in oil recovery. This study proved that using FeRM for the reduction of hydro-swelling in low-permeability reservoirs holds great potential for enhanced oil recovery.

Supplementary Materials

The following are available online at https://www.mdpi.com/article/10.3390/en15124393/s1, Figure S1. A real photo of core displacement apparatus device. Figure S2. Changes in the physical hydro-swelling properties of smectite clay minerals by the action of FeRM and KCl. Figure S3. The size distribution characteristics of mineral particles before and after FeRM treatment. (a) Before FeRM treatment; (b) after FeRM treatment. Figure S4. The height and efficiency of the core plug hydro-swelling by FeRM (a–d) at different temperatures and pressures. (a) FeRM action (30 °C and 0.1 Mpa); (b) FeRM action (40 °C and 0.1 Mpa); (c) FeRM action (35 °C and 1.0 Mpa); (d) FeRM action (35 °C and 2.0 Mpa). Figure S5. Characteristics of the pore-throat size and capillary pressure curve, and structure distribution of the cores before and after FeRM action in the core displacement tests. Graphs are presented in terms of both mercury saturation frequency columns and capillary pressure curves, where the pore-throat radius is represented on the logarithmic scale x-axis. The higher the mercury saturation frequency value, the worse the pore-throat connectivity and the greater the mercury injection resistance, and vice versa for mercury saturation. The blue arrows and circles in the figure refer to mercury saturation in the pore-throats at the average radius. Table S1. Characteristics of produced water. Table S2. The ionic composition of the injection fluid.

Author Contributions

Conceptualization, C.W., Z.Z. and K.G.; Data curation, W.H.; Formal analysis, K.C.; Investigation, C.W. and J.Z.; Methodology, L.L. and J.Z.; Project administration, K.C. and Z.Z.; Resources, L.L. and Z.Z.; Supervision, W.H.; Writing—original draft, K.C.; Writing—review & editing, H.W. and K.G. All authors have read and agreed to the published version of the manuscript.

Funding

This research was funded by [National Natural Science Foundation of China] grant number [No.52174027], [Natural Science Foundation of Shaanxi Province] grant number [No.2021JQ-012], [China Postdoctoral Science Foundation General Project] grant number [No.2020M683502], and the APC was funded by [No.2021JQ-012].

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Informed consent was obtained from all subjects involved in the study.

Data Availability Statement

Not applicable.

Acknowledgments

This research was financially supported by the National Natural Science Foundation of China (No.52174027), Natural Science Foundation of Shaanxi Province (No.2021JQ-012), and China Postdoctoral Science Foundation General Project (No.2020M683502). The authors are grateful to the State Key Laboratory of Heavy Oil Processing of China for their technical assistance during this work.

Conflicts of Interest

The authors declare no conflict of interest.

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Figure 1. Schematic diagram of the core displacement tests. (1) Flooding pump; (2) flooding fluid vessel; (3) crude oil in the vessel; (4) waterflooding fluid in the vessel; (5) microbial flooding fluid in the vessel; (6) constant-temperature oven; (7) flooding pressure gauge; (8) peripheral pressure gauge; (9) core holder; (10) pressure transducer; (11) exit pressure gauge; (12) measuring cylinder; (13) manual metering pump; (14) hydrating device.
Figure 1. Schematic diagram of the core displacement tests. (1) Flooding pump; (2) flooding fluid vessel; (3) crude oil in the vessel; (4) waterflooding fluid in the vessel; (5) microbial flooding fluid in the vessel; (6) constant-temperature oven; (7) flooding pressure gauge; (8) peripheral pressure gauge; (9) core holder; (10) pressure transducer; (11) exit pressure gauge; (12) measuring cylinder; (13) manual metering pump; (14) hydrating device.
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Figure 2. The hydro-swelling properties of the core plug with water flooding (a) and with FeRM flooding (b).
Figure 2. The hydro-swelling properties of the core plug with water flooding (a) and with FeRM flooding (b).
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Figure 3. The inhibition efficiency and shrinkage efficiency of hydro-swelling by FeRM action at different temperatures and pressures. (a) Inhibition efficiencies at different temperatures; (b) shrinkage efficiencies at different temperatures; (c) inhibition efficiencies at different pressures; (d) shrinkage efficiencies at different pressures.
Figure 3. The inhibition efficiency and shrinkage efficiency of hydro-swelling by FeRM action at different temperatures and pressures. (a) Inhibition efficiencies at different temperatures; (b) shrinkage efficiencies at different temperatures; (c) inhibition efficiencies at different pressures; (d) shrinkage efficiencies at different pressures.
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Figure 4. The enhanced oil recovery by FeRM in core displacement tests.
Figure 4. The enhanced oil recovery by FeRM in core displacement tests.
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Figure 5. Effects of the permeability and waterflooding injection pressure in the cores by FeRM action. Core #1 (blank control, without flooding); core #2 (experimental control, waterflooding, without FeRM); core #3 (experiment, 5% of FeRM flooding).
Figure 5. Effects of the permeability and waterflooding injection pressure in the cores by FeRM action. Core #1 (blank control, without flooding); core #2 (experimental control, waterflooding, without FeRM); core #3 (experiment, 5% of FeRM flooding).
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Figure 6. The biochemical process of swelling reduction, injection augmentation, and oil recovery enhancement of the low-permeability reservoirs by FeRM.
Figure 6. The biochemical process of swelling reduction, injection augmentation, and oil recovery enhancement of the low-permeability reservoirs by FeRM.
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Table
Table 1. The properties of the synthetic cores.
Table 1. The properties of the synthetic cores.
Core NumberDiameter (cm)Length (cm)Pore Quality (g)Porosity (%)Gas Permeability (mD)Water Permeability (mD)Smectite Clay Mineral
Content (%)
#12.509.651.6648.4737.652.517–8
#22.509.651.6178.4335.652.387–8
#32.509.651.6388.4536.652.437–8
Table
Table 2. Experimental design of core displacement tests.
Table 2. Experimental design of core displacement tests.
Core NumberPretreatmentDisplacement TestsObjectives
#1Without treatmentWithout floodingBlank control
#2Hydration + crude oilWaterflooding
(without FeRM)		Experimental control
#3Hydration + crude oilMicrobial flooding
(5% FeRM)		To investigate the inhibition/shrinkage effects of FeRM
Table
Table 3. Distribution and structure of pore-throats before and after water/FeRM flooding.
Table 3. Distribution and structure of pore-throats before and after water/FeRM flooding.
Core
Number		Pore-Throat CoefficientStructure CoefficientPore-Throat Sorting CoefficientAverage Pore-Throat RadiusPore-Throat Radius
<0.01 μm, %		Pore-Throat
Radius
0.01–0.05 μm, %
#16.283.671.3212.85340.8844.50
#25.822.551.769.11349.9537.98
#36.494.551.3811.96544.1542.48
Pore-Throat
Radius
>0.05 μm, %		Capillary Pressure (10%), MpaCapillary Pressure (30%), MpaCapillary Pressure (50%), MpaPore-Throat Radius (10%), μmPore-Throat Radius (30%), μmPore-Throat Radius
(50%), μm
14.620.0340.0520.06922.32114.05910.119
12.070.0410.0560.08720.32713.0668.466
13.570.0320.0470.06322.94215.83111.611
Note: Core #1 (blank control, without flooding); core #2 (experimental control, waterflooding, without FeRM); core #3 (experiment, 5% of FeRM flooding).
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Cui, K.; Wang, C.; Li, L.; Zou, J.; Huang, W.; Zhang, Z.; Wang, H.; Guo, K. Controlling the Hydro-Swelling of Smectite Clay Minerals by Fe(III) Reducing Bacteria for Enhanced Oil Recovery from Low-Permeability Reservoirs. Energies 2022, 15, 4393. https://doi.org/10.3390/en15124393

AMA Style

Cui K, Wang C, Li L, Zou J, Huang W, Zhang Z, Wang H, Guo K. Controlling the Hydro-Swelling of Smectite Clay Minerals by Fe(III) Reducing Bacteria for Enhanced Oil Recovery from Low-Permeability Reservoirs. Energies. 2022; 15(12):4393. https://doi.org/10.3390/en15124393

Chicago/Turabian Style

Cui, Kai, Chengjun Wang, Li Li, Jungang Zou, Weihong Huang, Zhongzhi Zhang, Heming Wang, and Kun Guo. 2022. "Controlling the Hydro-Swelling of Smectite Clay Minerals by Fe(III) Reducing Bacteria for Enhanced Oil Recovery from Low-Permeability Reservoirs" Energies 15, no. 12: 4393. https://doi.org/10.3390/en15124393

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