High-Pressure Microscopic Investigation on the Oil Recovery

Article pubs.acs.org/EF

High-Pressure Microscopic Investigation on the Oil Recovery Mechanism by in Situ Biogases in Petroleum Reservoirs WeiYao Zhu,† JiaXin Zhao,† HongYan Han,† GangZheng Sun,‡ and ZhiYong Song*,† †

School of Civil and Environmental Engineering, University of Science and Technology Beijing, Beijing 100083, People’s Republic of China ‡ Oil Production Research Institute, Shengli Oil Field Limited Company, SINOPEC, Dongying, Shandong 257000, People’s Republic of China ABSTRACT: Biogases, including CO2 and CH4, are an essential category of the complex metabolites in microbial enhanced oil recovery (MEOR). However, the recovery mechanisms and contributions of in situ biogases have not been individually studied. A microbial consortium from oil fields, which produced gases but few metabolites, was inoculated in microscopic flooding experiments mimicking reservoir pressure. Additional oil [14.8% of the original oil-in-place (OOIP)] was recovered. In terms of gas yields, porous media were favorable culturing substrates compared to bottles (up to 1.2 and 0.42 mL of biogas per mL of medium, respectively). Under pressurized reservoir conditions (8 MPa), contributions from typical mechanisms, including oil displacement and pressurization by gas bubbles, can be excluded as a result of the effective biogas dissolution in crude oil. The dissolved gases promoted the spontaneous expansion of microbial activities, so that 34.1% of the additional oil was recovered from the margin regions, area of which only occupied 19.76% of the model. Therefore, the significant sweep efficiency enhancement is suggested to be the dominant recovery mechanism exhibited by in situ biogases. The findings also provided a new perspective on the effects of CO2 and CH4 (natural gas) flooding on hydrocarbon migrations in reservoirs.

1. INTRODUCTION After primary and secondary oil recovery steps, i.e., elastic recovery and waterflooding, one third to one half of the original oil remains in reservoirs.1 To meet increasing demands, tertiary oil recovery techniques, commonly known as enhanced oil recovery (EOR), are required.2 One of these methods, microbial enhanced oil recovery (MEOR), is an eco-friendly process that employs microbes and their metabolites to release oil trapped in pores.3 For decades, numerous lab-scale experiments of microbial flooding have exhibited promising results4,5 and several field applications have demonstrated even better economic efficiency than conventional chemical EORs.6−8 However, MEOR is a complicated process, involving a variety of recovery mechanisms by different microorganisms and metabolites, such as biosurfactants, biogases, biopolymers, and organic acids.1,6,9 In addition, microbial community structures are known to vary temporally and spatially in reservoir as a result of the variations of environmental conditions during waterflooding, which indicated that, in a single reservoir, each area might be dominated by different microorganisms performing their specific mechanisms and efficiencies.10,11 The complexity and uncertainty of the microbial processes have been considered to be the major barriers for elucidating their mechanisms.1,12 To understand these processes better, researchers began to individually examine the contributions of different metabolites involved in MEOR. Among these metabolites, biosurfactants have attracted the most attention.1,2,13−15 However, the aerobic biosynthesis of surfactants could be limited by the strictly anaerobic environments, which generally require the addition of electron acceptors, such as nitrates and dissolved oxygen.4,16−18 In addition, the rich oil areas in water-flooded reservoirs are © 2015 American Chemical Society

generally far from the injection well, environments of which are strictly anaerobic and recalcitrant to aerobic microbial activities.19 In contrast, indigenous microorganisms, especially syntrophic bacteria and archaea, can naturally and anaerobically metabolize organic acid and even petroleum hydrocarbons to produce biogases (methane) in reservoirs. In addition to the produced biogases, the anaerobic metabolism was also suggested to significantly contribute to MEOR by reducing the product inhibitions of the reservoir metabolic system.20−25 Therefore, by determining the oil recovery mechanisms of the in situ-produced biogases, MEOR might be applied more economically in reservoirs with extreme environments. In terms of the recovery mechanisms, Donaldson and Obeida suggested that biogases dissolved in oil and brine, thereby establishing a solution gas drive mechanism;26 however, no other studies further reported such a significant volume of biogas production. Except the volume, their gas sources were also distinct; thus, the solution gas drive mechanism cannot be directly applied for general MEOR conditions.27 Therefore, the present paper focused on the in situ biogas production by indigenous microbes from the reservoir to mimic the practical gas source and production. With regard to the time-consuming microbial activity, lab-scale experiments usually require a shutin period after nutrient injections, instead of successive flooding; thus, the in situ microbes can reproduce adequately with enough retention time in the limited pore volumes of cores.28,29 Several recovery mechanisms, such as reservoir repressurization and reducing oil viscosity and interfacial Received: August 20, 2015 Revised: October 26, 2015 Published: November 18, 2015 7866

DOI: 10.1021/acs.energyfuels.5b01906 Energy Fuels 2015, 29, 7866−7874

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Energy & Fuels Table 1. Percentages of Gas Components Produced from Bottles cultured consortium with crude oil cultured consortium without crude oil sterilized medium with crude oil

H2 (%)

O2 (%)

N2 (%)

CO2 (%)

H2S (%)

CH4 (%)

other alkanes (%)

2.27 0.62 0.00

0.00 0.00 0.00

70.14 70.31 98.19

9.98 15.47 0.00

0.89 1.48 1.80

15.76 12.06 0.00

0.96 0.05 0.00

duration of the shut-in was determined according to the cell growth in bottles and the morphological dynamic in micromodels. Thus, the present experiments were designed to culture gas-producing consortium in a micromodel during waterflooding experiments under atmospheric and reservoir pressures, respectively. On the basis of the fluid morphology, flooding dynamic, and oil recovery, the major recovery mechanism of in situ biogases under reservoir pressure could be revealed. 2.2. Crude Oil and Brine. The crude oil used in this study was sampled from an oil reservoir of Shengli Oil Field (China). The crude oil composition was as follows: 2.80% (w/w) sulfur, 0.44% (w/w) nitrogen, 19.66% (w/w) aliphatic hydrocarbons, 39.09% (w/w) aromatic hydrocarbons, 27.36% (w/w) polar fractions with heteroatoms nitrogen, sulfur, and oxygen, and 13.89% (w/w) asphaltenes. Additionally, the viscosity, American Petroleum Institute (API) gravity, and density of the tested crude oil were 1077 mPa s, 13.7°, and 0.987 g/cm3, respectively. To simulate the salinity of the injected fluids in this field, the brine used for waterflooding in this study contained NaCl (3200 mg/L), MgCl2 (100 mg/L), and CaCl2 (200 mg/L), with the pH adjusted to 7.0. 2.3. Consortium and Culturing Method. The microbial consortium, which was previously enriched from the produced water of an oil reservoir, contained species of bacteria and methanogenic archaea producing biogases.35 The consortium was cultured in a 250 mL serum bottle sealed with a rubber stopper and a screw cap to maintain anaerobic conditions. To avoid colony precipitation, the bottles were placed in an incubator shaker at 37 °C and 180 revolutions/min for 20 days. The culture medium was composed of peptone (3 g/L, Angel Yeast, China), sodium formate (3 g/L), sodium acetate (3 g/L), yeast extract powder (3 g/L), KH2PO4 (0.227 g/L), K2HPO4 (0.348 g/L), NH4Cl (0.5 g/ L), MgCl2 (0.5 g/L), CaCl2 (0.25 g/L), NaHCO3 (0.85 g/L), and NaCl (2.25 g/L), with the pH adjusted to 7.2. To establish the strictly anaerobic conditions, the dissolved oxygen (DO) in the medium was removed by boiling and nitrogen sweeping and the residual DO was subsequently reduced by L-cysteine monohydrochloride (0.5 g/L). Biomass was measured by optical density at a 600 nm wavelength (OD600). To demonstrate the induction effect of crude oil on the composition of biogases, three parallel sets of experiments were conducted. The first two sets cultured the consortium with and without crude oil (1 mL), respectively, and the third set with crude oil (1 mL, i.e., the control) was not inoculated with the consortium (Table 1). 2.4. Volume and Composition of Biogases. The produced gases were collected with a 500 mL gas collection bag connected to the serum bottle and were quantified by an air-drainage method. The compositions were analyzed by a HP7890A gas chromatograph (GC) equipped with a packed column in stainless steel (Agilent G359180129) and two detectors. The temperatures of the injector and detector were set at 120 and 250 °C, respectively. Hydrogen, oxygen, nitrogen, carbon dioxide, and H2S were detected by a thermal conductivity detector (TCD). Methane was detected by a flame ionization detector (FID). Nitrogen was used as the carrier gas for hydrogen, and helium was used for other gases. 2.5. Volatile Organic Acids. Volatile organic acids, including acetate, were analyzed by an Agilent 4890 GC system equipped with a FID and capillary column (Durabond DB-FFAP). Nitrogen was used as the carrier gas. The temperatures of injector and detector were set at 250 and 300 °C, respectively. The column temperature was 240 °C.

tension, which are generally considered as the major processes enhancing oil recovery, were not yet demonstrated visually and experimentally.18 Furthermore, because of the difficulties of gas sampling and quantification, the gas volumes were only determined in bottles, instead of in situ from porous media.18,30 To solve these issues, the present study was designed to directly demonstrate the morphological and quantified dynamics of phases (water, oil, and gas) in pores using a two-dimensional microscopic model. However, the previous literature on flooding in microscopic models were generally conducted under atmospheric and low pressures, which could not mimic the practical status of biogases in reservoirs as a result of its considerable compressibility under high pressure.28,29 To mimic the extreme conditions in the present study, the conventional microscopic flooding system with artificial pore space in our laboratory has been redesigned to operate at high pressure and high temperature (up to 25 MPa and 150 °C). Using this system, the pore-scale processes of oil recovery by indigenous microbial communities and biosurfactants have been investigated previously.12,31 The objectives of the present study are to (i) determine the composition and quantity of in situ biogases produced in pore space, (ii) clarify the mechanisms on crude oil recovery by biogas, and (iii) distinguish the contribution of biogases from other microbial metabolites.

2. EXPERIMENTAL SECTION 2.1. Design of the Experiment. The design of the experiment is a descriptive discipline, which has broad applications among the engineering, natural, and social sciences.32,33 Before designing the experiments, the objectives and then the variables must be set and carefully selected. The ultimate objective of the present paper was to reveal the mechanism on oil recovery by in situ biogases under high pressure. With regard to the selection of variables, there are numerous factors affecting microbial and flooding processes.34 As the first attempt on this purpose, the list of experimental variable was narrowed as much as possible in the present paper. First, the characteristics of porous media were fixed by usng a single micromodel frequently used in our previous studies.12,31 Second, the flooding parameters were selected according to our previous flooding experiments to achieve adequate comparisons to other flooding techniques.12,31 Third, with regard to the environmental factors, such as the temperature and pressure, they are all essential to fluid properties and microbial activities. Because microorganisms generally adapt in a limited temperature range, the reservoir temperature (i.e., the original habitat temperature of the gas-producing microorganisms) was selected in the present experiments.35 With regard to the pressure, the reservoir and atmospheric pressures were selected for in situ biogas production, so that the specialties of biogases under high pressure could be demonstrated by comparison to previous atmospheric experiments. To simplify the study, the toughest problem in the experimental design was how to separate the gas production from different functional metabolites. On the basis of the purposive efforts for years, a microbial consortium from the oil reservoir, which was able to produce adequate biogas without significant biosurfactants and biopolymers, was selected in this study to exhibit the sole effects of biogases.12,35 To ensure the in situ microbial activities enough retention time, lab-scale experiments usually require a shut-in period after injections of nutrients and microbes, instead of successive flooding.28,29 The 7867


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Energy & Fuels 2.6. Surface Tension. The surface tension was measured at 40 °C using a semi-automatic tensiometer (Force Tensiometer K20, Krüss, Germany). Each measurement was performed 4 times. 2.7. Emulsification Index. The emulsification activity of the supernatant was characterized by the emulsification index at 40 °C. After 5 mL of crude oil was added to 5 mL of culture, the mixture was shaken in a vortex for 2 min and kept still for a given time interval. The emulsification index (E) was then calculated by the ratio of He (the height of the emulsion) to Ht (the height of the total mixture). 2.8. Extracellular Polymeric Substances (EPS). The EPS were extracted using a mild method and a harsh method in sequence, including an oscillation−ultrasound method followed by a cationexchange resin technique.36 Next, the carbohydrates and proteins were analyzed by a colorimetric method and Bradford method, respectively.37,38 2.9. Microscopic Flooding Apparatus. The two-dimensional microscopic flooding apparatus shown schematically in Figure 1a was

Figure 2. Procedures of flooding experiments: (a) comparative flooding with atmospheric gas production, (b) standard flooding at reservoir pressure, and (c) control with waterflooding only.

Figure 1. (a) Apparatus of the microscopic flooding experiment, (b) top-view photo of the oil-saturated two-dimensional microscopic model, and (c) schematic diagram of the flow region division of the model.

oil was injected continuously to simulate the original oil-in-place (OOIP, i.e., the oil saturation stage). Afterward, the model was flooded with 5.5 PV brine to establish a residual oil saturation status (i.e., the waterflooding stage). Subsequently, 0.1 PV consortium culture and 0.5 PV oxygen-free medium were injected successively, and the model was sealed for 20 days to accumulate in situ biogas, which was followed by a post-waterflooding stage with 1.0 PV brine injection. The rates of all injections in the microscopic flooding experiments were 0.003 mL/ min (the capillary number of waterflooding was 5.3 × 10−7). During the process, the micromodel was kept at 40 °C and an overpressure of 8 MPa to mimic reservoir conditions. The microscopic images and videos of the model were continuously recorded to analyze the morphological variations of the fluids in pore spaces. After each flooding experiment, the micromodel was cleaned by circulating with petroleum ether and distilled water. To estimate the gas volume produced in the micromodel, another microscopic flooding experiment was conducted with gas production under atmospheric pressure, which is shown in Figure 2a. Additionally, a control flooding experiment was conducted without microbial effects, as shown in Figure 2c. All of the flooding experiments were conducted 4 times. 2.11. Saturation Determination in the Micromodel. After the original images were sharpened, the oil saturations recorded in the images were determined using a MATLAB program. The program was able to distinguish the water, gas, oil, and glass phases by given pixel

described in our previous paper.12 The experimental setup was composed of two primary systems: a flooding system and an imagecapturing system. The flooding system consisted of a syringe pump, accumulators, and a model holder, and the image-capturing system included a microscope, camera, and computer. The heart of the apparatus was the micromodel (Figure 1b), of which the pore structure was identical to the cross-section image of a natural sandstone core and was etched onto a flat glass plate. This plate was covered by another glass plate to create an enclosed pore space. The covering plate has an inlet and outlet hole at the two opposite corners, allowing fluids to flow through the pore network. The external size, pore volume, porosity, and permeability of the model were 40 × 40 mm, 50 μL, 41.7%, and 6.73 μm2, respectively. In the steel model holder (a hollow cylinder), the micromodel was clamped horizontally by thick glasses and filled with water to load the overpressure, which allowed the light to travel through. This special holder and a backpressure valve were used to maintain oil-reservoir-like high pressures. 2.10. Flooding Procedures. On the basis of the standard experimental procedure (Figure 2b), the micromodel was first saturated by injecting 2.0 pore volumes (PV) of brine under vacuum conditions (i.e., the water saturation stage). Next, 2.0 PV of the crude 7868


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Figure 3. Time-course profiles of cell growth and metabolites in bottles and the micromodel: (a) total gas volume and biomass in bottles, (b) methane and carbon dioxide produced in bottles, (c) acetate produced in bottles, and (d) gas saturation in the micromodel. intensity thresholds. The oil saturation was then calculated on the basis of the area proportion of the oil phase to the total pores.12 As a result of the good connectivity of the pores designed in the present micromodel, the irreducible water saturation was undetectable after the oil saturation stage; i.e., the original oil saturation was 100%. Therefore, the amount of oil recovery can be calculated as the difference between 100% and the remaining oil saturation. 2.12. Partition of the Sweep Area. To demonstrate the sweep efficiency during flooding, the micromodel was divided into three specific regions along the normal of the major flooding trajectory to individually measure the oil saturations (Figure 1c). The three regions, including the main stream, the transitions, and the margins, occupied 39.39, 40.84, and 19.76% area of the total model, respectively. In the three regions, eight, eight, and four images of different sites were recorded, respectively. The oil saturation of each region was reported as the arithmetic average of the oil saturations of all recorded sites in the region. In terms of the total model, the oil saturation was the average of the three regions weighted by their area proportions.

measured in bottles. Figure 3a shows that the biomass considerably increased 1 day after inoculation and then reached and maintained the highest level (OD600, 0.45−0.47) after 5 days. The growth dynamics could be described by the Monod model, which was used in previous studies to describe the dynamics of indigenous microbes producing surfactants and/or degrading hydrocarbons.39 However, under the strictly anaerobic conditions, the relatively short log phase of the present consortium (within 24 h) resulted in a lower biomass during the stationary phase (only a quarter of the previous study according to the OD600).40 A number of studies have indicated that microbial cells themselves can enhance oil recovery by wettability alteration or bioclogging.40−42 Therefore, with regard to the oil recovery by the in situ biogas production, the low biomass of the strictly anaerobic microorganisms would introduce less additional effect on oil recovery by cells, which was an advantage on the mechanism study compared to facultative microbes.19,25 The biogas volume constantly increased over 6 days, up to 0.42 mL of gas/mL of liquid medium (Figure 3). Hydrogen, methane, and CO2 were the major products of the consortium (Table 1). The existence of H2S in the culture without crude oil indicated that H2S was not mainly derived from crude oil but

3. RESULTS AND DISCUSSION 3.1. Growth and Metabolites of the Gas-Producing Consortium. To assess the gas production levels in the micromodel, the basic profiles of the consortium, including biomass, gas composition, and other metabolites, were first 7869


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Energy & Fuels Table 2. Comparison of the Media Characteristics before and after Culture EPS

original medium consortium culture

surface tension (mN/m)

emulsification index (%)

viscosity (mPa s)

carbohydrates (mg/L)

protein (mg/L)

molecular weight (number average)

53.3 55.9

1.3 2.3

0.8 0.7

186.5

0.031

4552

situ flooding conditions.18,30 Because of the difficulty of measuring the small volume of gas produced from cores, the high-pressure microscopic model was used in this study to observe gas production directly in artificial pore spaces. Furthermore, the microscopic experiment was initially conducted under atmospheric pressure (Figure 4) as a baseline for the experiments under reservoir pressure, as a result of the gas compressibility.

from excess L-cysteine in the initial medium.43 Furthermore, according to the comparison between the consortium culture and the sterilized medium in Table 1, the crude oil produced no hydrogen or volatile hydrocarbons by itself, while it stimulated the consortium to produce more H2 and CH4. Similarly, Kobayashi et al. also reported that the presence of crude oil improved the methane production.22 Excluding the nitrogenbalanced atmosphere in the bottles, methane and CO2 were the major components of the biogases, reaching 8.0 and 19.7%, respectively (Figure 3b). A previous experimental study on MEOR at a low temperature (22.6 °C) reported that an indigenous community produced 0.93 mL of biogas per medium in bottles under facultative conditions, of which the methane percentage (6.21%) was similar to the present paper. However, the gas production rate of the strictly anaerobic consortium in the present paper was 5.8 times higher than the facultative gas production rate in the literature.44 Therefore, although biomass was relatively low under strictly anaerobic conditions, the gas production was rapid enough to be performed adequately in practical reservoirs, because the retention time in the reservoir of waterflooding was generally 30−90 days.19 Unlike biogases, acetate increased to approximately 400 mg/ L in 4 days while subsequently declining after 7 days (Figure 3c). The decline can be attributed to the syntrophic acetateoxidizing process involved in the consortium, which produces methane and makes acetate both the metabolite and substrate.35 This rise−fall pattern of acetate was consistent with the results of several large-scale flooding experiments and field pilots of MEOR, which indicated that, in reservoirs, there were integrated microbial metabolic systems to mineralize lowmolecular-weight organics; i.e., the biogas production process might be potentially included in these scenarios.19 With regard to the other functional metabolites, the production of biosurfactant, bioemulsifier, and EPS was analyzed. The surface tension and emulsification activities were tested to demonstrate whether the consortium produced enough biosurfactants or bioemulsifiers to enhance oil displacement.12,45 As shown in Table 2, the surface tension of the consortium culture was even 2.6 mN/m higher than the original medium, which indicated that the consortium did not produce a significant level of biosurfactant, i.e., no interfacial activity. Besides, the emulsification indices of the culture were lower than 3%, which indicated that there was no significant emulsion activity in the culture. Similarly, the results of EPS indicated that only 186.5 mg/L carbohydrate and few proteins were contained, which was not enough to affect the culture viscosity significantly. This result was consistent with the negligible changes on medium viscosity after culture (Table 2). Thus, the effects of biosurfactant, bioemulsifier, and biopolymer on oil recovery could be excluded in the present culture. 3.2. Gas Production in the Microscopic Model. There have been a number of studies on biogas production during flooding experiments under reservoir conditions; however, quantified results were only obtained in bottles, instead of in

Figure 4. Microscopic images of the biogas (indicated by circles) during the shut-in stage under atmospheric pressure: (a) initial status, (b) 2 days, (c) 4 days, (d) 6 days, and (e) 14 days after nutrient injection, and (f) after the post-waterflooding.

Under atmospheric pressure, the separated biogas phase (gas bubbles) emerged rapidly only 1 day after nutrient injection (Figure 4). The gas saturation increased until the 14th day (up to 39.2%; Figure 3d), which equals 1.2 mL of biogas/mL of water (gas saturation divided by water saturation). In terms of the spatial distribution of the bubbles, the gas saturations in the main stream, transition, and margin regions were 51.9, 42.8, and 15.1%, respectively. Therefore, most bubbles (97.1%) were distributed in the main stream and transition regions, pores of which were flooded by more water and received more nutrients. The results showed that the consortium could produce gases in 7870


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Energy & Fuels both bottles and porous media. In addition, the duration of gas production in porous media (14 days, 1.2 mL of gas/mL of medium) was further prolonged, and the volumes were considerably higher than those in bottles (6 days, 0.42 mL of gas/mL of medium). Furthermore, in the first 6 days, the average daily production rate (0.08 mL of gas/mL of medium) was also higher than that in bottles (0.069 mL of gas/mL of medium). This may be attributed to the fine mixture between cultures and crude oil as a result of the high specific surface area of porous media, which resulted in better mass transfer.22 Therefore, the porous media provided a more favorable habitat for gas-producing microorganisms. In the previous literature, solely based on those results from bottles, the production rate and impact scope of biogases in reservoirs might have been underestimated. Unlike the atmospheric experiment, no gas bubbles appeared under reservoir pressure (Figure 6). However, a few distinct

Figure 6. Microscopic images of the morphological variation of crude oil during the shut-in stage under reservoir pressure: (a) initial status, (b) 1 day, (c) 4 days, (d) 8 days, and (e) 10 days after nutrient injection, and (f) after the post-waterflooding. The arrows indicate the same site where the oil blobs with lighter color emerged and varied.

bubbles shrunk (Figure 5b) and entirely disappeared when the pressure exceeded 0.6 MPa (Figure 5c). Then, the fluid pressure was kept at 8 MPa for 1 h and then was gradually reduced to determine whether the gas bubbles would reappear at atmospheric pressure. The result showed that no gas bubble (free gas phase) reappeared as the pressure returned to atmospheric pressure, but small dispersions of crude oil (light yellow emulsion in the water phase) appeared around the original locations of bubbles (Figure 5d). This phenomenon indicated that the increased pressure not only compressed the bubbles in size but also accelerated the gas dissolution into oil. However, the gas volumes were far lower than the saturated solubility of crude oil; thus, the gases could not escape from oil once dissolved.46 With regard to the oil dispersion, it may be attributable to the extraction of lightweight components from crude oil, because the colloid structure of the crude oil might be partially destructed by the biogas dissolution.47 Therefore, under reservoir pressure, the in situ biogases were all dissolved in liquids, of which volumes were not large enough to improve reservoir pressure significantly. Additionally, in comparison to the huge gas volume (16−35.6 m3 of gas/m3 of liquid) injected during the solution gas drive, the oil recovery mechanism of the solution gas drive was obviously not suitable for the in situ biogases.27 3.3. Morphology and Behavior of Biogas during the Shut-in Period. During the atmospheric shut-in period, the oil, water, and gas phases spontaneously moved as a result of the constant production of biogases in the first 14 days. On the basis of these random movements, a few segments of the residual oil (even the oil in dead-end pores) were displaced by

Figure 5. Microscopic images of the morphological variation of biogas (indicated by circles) during the compressing and decompressing processes after atmospheric production: (a) initial status, compressed to (b) 0.1 MPa and (c) 8 MPa, and (d) decompressed to atmospheric pressure. The arrows mark the original site of the biogas bubble.

blobs with lighter color (brown) appeared in the crude oil phase (black) 1 day after the nutrient injection. The blobs increased in size during the following 10 days up to 63.9% of the oil phase, i.e., 26.1% of the total pores. The duration of blob size growth (10 days) was close to the gas production period under atmospheric conditions (12 days). Thus, the effect of the pressure on the duration of gas-producing activity was not significant. With regard to the blob distributions in the model, the percentages of blob area (blob saturation in pores) in the transition and margin regions (27.0 and 28.7%) were even higher than that in the main stream (23.6%). These results under reservoir pressure showed the considerably wider distribution of oil blobs than the bubbles under atmospheric pressure. This finding indicated that the microbial activities were spontaneously and considerably expanded in pores under high pressures. This type of distribution has not been previously reported. Besides, to further correlate the gas states under different pressures, the gas bubbles produced under atmospheric conditions were compressed by increasing fluid pressure after the shut-in period (Figure 5). As the pressure increased, the gas 7871


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Energy & Fuels Table 3. Remaining Oil Saturations and Oil Recoveries during Flooding Experimentsα remaining oil saturation (%) region comparative flooding (atmospheric gas production)

standard flooding (reservoir pressure)

control (waterflooding)

α

main transition margin weighted average main transition margin weighted average main transition margin weighted average

after waterflooding

after culture injection

additional oil recovery (% OOIP)

after shut-in and post-waterflooding

by culture injection

by biogas production

total

43.9 54.8 58.6 51.3

± ± ± ±

3.3 3.3 5.6 3.0

34.6 40.7 39.1 38.0

± ± ± ±

3.7 1.9 4.1 2.7

22.4 29.2 31.4 27.0

± ± ± ±

1.3 3.5 2.3 1.7

9.3 14.1 19.5 13.3

± ± ± ±

0.9 1.9 3.5 0.6

12.2 11.5 7.7 11.0

± ± ± ±

4.1 1.7 2.5 1.4

21.5 25.6 27.2 24.3

± ± ± ±

3.7 1.6 3.6 1.7

45.7 56.5 60.1 52.9

± ± ± ±

4.4 4.8 4.1 3.5

33.4 44.8 43.7 40.1

± ± ± ±

5.8 4.4 5.8 4.4

21.1 32.8 18.2 25.3

± ± ± ±

0.9 3.7 2.9 2.2

12.4 11.7 16.4 12.9

± ± ± ±

4.4 1.4 3.6 1.5

12.3 12.0 25.5 14.8

± ± ± ±

5.1 1.1 4.8 2.2

24.6 23.7 41.9 27.6

± ± ± ±

3.7 1.1 1.7 1.6

44.2 59.5 60.8 53.8

± ± ± ±

2.4 3.9 3.3 2.4

42.0 52.5 53.7 48.6

± ± ± ±

1.2 3.1 3.0 1.8

2.2 7.0 7.1 5.1

± ± ± ±

1.3 2.0 1.5 1.4

Weighted average is weighted by the area proportion of each region.

OOIP); thus, the difference between their total AORs (3.3% OOIP) were primarily derived from the gas production stage, i.e., the shut-in stage (3.8% OOIP). This result demonstrated that the in situ biogases under pressure could achieve higher AOR than under atmospheric pressure. A more in-depth comparison between the regions of the model revealed that the additional 3.8% OOIP under high pressure was mostly attributed to the considerably higher AOR in the margin regions (25.5% OOIP), which was 3 times higher than that of the atmospheric pressure (7.7% OOIP). Thus, the apparent oil recovery mechanism of biogases under reservoir pressure seemed to be the enhancement of sweep efficiency. With regard to the reasons of the apparent mechanisms, although many studies have reported that biogas productions are involved in various microbial-flooding experiments, the recovery mechanism of biogases has never been individually investigated from the complex microbial mechanisms.18,30 The complex mechanisms are derived from different metabolites and activities, such as the interfacial tension reductions by biosurfactants, the oil viscosity reductions by solvents and gases, the mobility ratio reductions by biopolymer, and the wettability alterations by biofilm.18 In the present study, efforts were made to isolate the effects of biogases as much as possible. Thus, a microbial consortium, which produced adequate biogas without other metabolites, was screened to be used in the experiments. The results of its metabolites and their physicochemical characteristics (Table 2) indicated that the productions of biosurfactants, bioemulsifiers, and biopolymers were low enough to be neglected.2,7,16,41 Therefore, these functional metabolites could be excluded from the mechanism analysis of the present experiments. Apart from metabolites, there is another key factor that affects oil recovery considerably, i.e., microbial cells themselves. A number of studies have suggested that microbial cells can enhance oil recovery by wettability alteration and/or bioclogging.40−42 To mimic in situ biogas production in the present study, numerous cells would be injected in the model and then reproduced adequately to produce biogases. As a result, the injection of consortium and culture achieved significant additional oil recovery (13.3 and 12.9% OOIP; Table 3) before gas production, while the cell contributions during gas production could not be easily separated from

the bubbles (Figure 4). With regard to the oil recovering from dead ends, our previous paper reported a similar process by a different mechanism, which was the pore−wall wettability alteration by the microbes spontaneously expanded in there.31 Under reservoir pressure, no gas bubbles and no spontaneous fluid movement were detected. The only dynamics under reservoir pressure was the size growth of the light-colored oil blobs in the oil phase. Thus, no residual oils were displaced from dead ends during the shut-in or even after the waterflooding stages, which was different from the observations of the atmospheric flooding experiment. Therefore, the mechanism of recovering oil from dead ends was likely absent in reservoirs under high pressure. Furthermore, during the atmospheric experiments, the bubbles generally emerged in the oil phase or were attached at the oil/water interfaces, which was consistent with the nucleation of gas bubbles around particles,27 while under reservoir pressures, all of the light-colored oil blobs were located inside the oil phase. Thus, the observations could not be simply explained by the physical nucleation of bubbles, while the microbial effects seemed to be essential here. The microbial characteristics, such as chemotaxis and lipophilicity of the cell wall, enabled cells to move toward oil/water interfaces and into the oil phase.40 3.4. Mechanisms and Contribution of Biogases to Oil Recovery. To demonstrate the effects of biogases in reservoirs, all flooding experiments after gas production were conducted under reservoir pressure, including the comparative experiment with atmospheric shut-in (Figure 2). The results of oil saturation and recovery during each stage are shown in Table 3. In terms of additional oil recovery (AOR), the control experiment achieved a total 5.1% OOIP, which was significantly lower than the other experiments with biogas production (24.3 and 27.6% OOIP, respectively). Although the AORs by the culture injection before gas production (13.3 and 12.9% OOIP) were subtracted from the total AORs, the remaining AORs (11.0 and 14.8% OOIP) after gas production remained nearly 1−2 times greater than that of the control experiment. This result indicated that the effects of in situ biogases on oil recovery were positive and significant. Further comparison between the two experiments with biogases showed that the AORs after culture injection were close (13.3 and 12.9% 7872


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production. However, the biogases were still limited in volume and were entirely dissolved in crude oil under reservoir pressure. Although the biogases were not enough to form a free gas phase in the reservoir, considerable additional oil (14.8% OOIP) was recovered. According to the AOR distributions in the different flooding regions, the apparent recovery mechanism of in situ biogas was the enhancement of sweep efficiency. Because there were no gas bubbles, biopolymer, and biofilm in the model, there was no detectable bioclogging in throats; i.e., the enhanced sweep efficiency was not mainly due to the conventional flow-resistance alteration. While, the wide distributions of the light-colored oil phase during shut-in were quantitatively consistent with the AOR distributions, which indicated that the enhanced sweep efficiency was based on the spontaneous expansion of microbial activities, including chemotaxis, reproduction, and biogas production. Furthermore, the comparison between different pressures showed that the high pressure did not inhibit the cell growth but accelerated the biogas dissolution in crude oil and the gas dissolution played a positive and essential role on the microbial expansions. The considerable AORs under reservoir pressure suggested that the microbial processes of in situ biogas production were more effective on oil recovery than our previous knowledge.

biogases, although the effects of cells were limited as a result of the low biomass of the strictly anaerobic consortium (Figure 3a). Finally, the AORs from the shut-in period, when the biogases were produced, were considered to be the combined contributions of biogases and relevant microbial cells. Then, further analysis was required to estimate the sole contribution of biogases. To solve this problem, the unexpected high recovery level (14.8% OOIP) under reservoir pressure became essential. In comparison to cell growth, gas status was obviously more sensitive to the pressure variation; thus, the AOR difference between the two pressures was more relevant to the biogases, instead of the cells. With regard to the higher recovery under reservoir pressure, the margin regions achieved the highest AOR (25.5%) among the three regions (Table 3), which contributed 34.1% of the total AOR from the limited area (only occupied 19.76% of the model). However, under atmospheric pressure, the margins only contributed 13.8% of its total AOR. Obviously, the gasproducing activity led to a considerably higher sweep efficiency under reservoir pressure. These differences were exactly consistent with the wide distribution of the light-colored oil blobs under reservoir pressure and the limited distribution of gas bubbles under atmospheric pressure. Therefore, the gas dissolution in crude oil (the light-colored oil blobs in appearance) is essential to the spontaneous expansion of microbial activity and then to the AOR. Generally, the improved sweep efficiency during microbial flooding was considered as a result of the selective clogging by cells or biofilms, which altered the distribution of the flow resistances among pore throats.41,42 Nevertheless, the low biomass (Figure 3) and insufficient biopolymer (Table 2) of the present consortium suggested that the bioclogging in the present experiments was negligible. Therefore, instead of the flow diversion during flooding, a different mechanism was proposed in the present paper: the biogas-producing consortium spontaneously expanded the metabolic activities and effects through pores by cell motility during the static shutin period, and the expansion could be enhanced by the gas dissolution in crude oil under high pressure.40 The positive effects of the spontaneous microbial expansion can be supported by other pore-scale investigations, which demonstrated that the biosurfactant-producing strains could retrieve more residual oil from deep dead ends than biosurfactants or chemical surfactants alone.12,31,48 However, the expansions into dead ends in the literature were within the branches directly connected to the flow channel, while the expansion in the present paper covered almost all of the pore spaces in the model. Thus, the gas-producing consortium showed a greater ability on expanding microbial activities and effects spontaneously, such as chemotaxis, reproduction, and biogas production. Furthermore, dependent upon the effective microbial activities enhancing sweep efficiency, the in situ biogas production methods are suggested to be more effective than previously reported to recover oil from reservoirs.

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Notes

The authors declare no competing financial interest.

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ACKNOWLEDGMENTS This study was supported by the National Natural Science Foundation of China (11372033) and the Fundamental Research Funds for the Central Universities (FRF-TP-15041A2). The authors are grateful to the Oil Production Research Institute of the Shengli Oil Field of SINOPEC for providing the fluid samples and the oil reservoir profiles.

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REFERENCES

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4. CONCLUSION To isolate the contribution of biogas from other functional metabolites during oil recovery, an indigenous microbial consortium from oil reservoirs, which only produced biogases without significant biosurfactant or biopolymer, was screened from an oil reservoir. According to the microbial culture during microscopic flooding experiments, the porous medium was found to be favorable for the consortium growth and gas 7873


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High-Pressure Microscopic Investigation on the Oil Recovery

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