Polymer-Assisted Microbial-Enhanced Oil Recovery - Energy & Fuels

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Polymer-assisted microbial enhanced oil recovery (MEOR) Cong-Yu Ke, Wu-juan Sun, Yong-bin Li, Junfeng Hui, Guomin Lu, Xiaoyan Zheng, Qun-Zheng Zhang, and Xun-Li Zhang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b00812 • Publication Date (Web): 18 Apr 2018 Downloaded from http://pubs.acs.org on April 19, 2018

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Polymer-assisted microbial enhanced oil recovery (MEOR) Cong-Yu Ke1, Wu-Juan Sun1*, Yong-Bin Li2, Jun-Feng Hui3, Guo-Min Lu1, Xiao-Yan Zheng3, Qun-Zheng Zhang1, Xun-Li Zhang1* 1

College of Chemistry and Chemical Engineering, Xi'an Shiyou University, Xi'an 710065,

China 2

Petroleum Production Engineering Research Institute, Huabei Oilfield Company, Renqiu

062552, China 3

School of Chemical and Engineering, Northwest University, Xi'an 710069, Shaanxi, PR

China

Running title:

Polymer-assisted MEOR

Type of Paper:

Full Research Article

Submitted to:

Energy & Fuels

* Correspondence to: Xun-Li Zhang, Wu-Juan Sun Address:

College of Chemistry and Chemical Engineering, University, Xi'an 710065, P.R. China

Phone/Fax:

+86 29 8838 2693

E-mail:

[email protected], [email protected]

1 ACS Paragon Plus Environment

Xi'an

Shiyou

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Abstract: Uncontrolled flow through different permeability zones in oil reservoirs remains a huge challenge during water flooding, which can significantly limit MEOR efficiency. The aim of the present work was to use polymer-based plugging to assist MEOR through laboratory simulation and field tests. An indigenous strain HB3 was evaluated under filedrelevant conditions. A polymeric HPAM/Cr(III) plugging system was optimised which was also compatible with the microorganism. Laboratory-based simulation demonstrated the selective plugging with HPAM/Cr(III) resulting in enhanced oil recovery more significantly in the low-permeability core, increasing from 12.8% to 47.5%, compared to that in the highpermeability one, from 47.1% to 63.2%. A subsequent microbial injection enhanced the oil recovery further, also with more effective enhancement in the low-permeability core, increasing from 49.5% to 70.0%, whilst from 67.5% to 78.0% in the high-permeability one. The field tests involving two water injection and nine oil production wells confirmed the improvement of deep profile control by polymer-based plugging, resulting in more uniform distribution of water absorption. With subsequent microbial injection, oil recovery was significantly enhanced, achieving an ultimate recovery of 57.6% and a cumulative oil increment of 3486 t in nine wells over the 7-month field tests. It was demonstrated that the application of polymer-based plugging significantly improved MEOR efficiency, providing a new route for EOR, especially for heterogeneous reservoirs. Key

words:

Polymer-based

plugging

·

Microbial

flooding

·

Laboratory-based

simulation· Sand pack column · Hydrolyzed polyacrylamide (HPAM)/Cr(III) · Field tests

1. INTRODUCTION In recent years, microbial enhanced oil recovery (MEOR) has been increasingly used to facilitate and increase oil production from oil reservoirs. Among different MEOR approaches, microbial flooding (or microbial enhanced water flooding) is considered as a very effective method.1-6 In a typical microbial flooding process, microbes and nutrients are injected into 2 ACS Paragon Plus Environment

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reservoirs from the injection wells where microorganisms and their metabolites move along with water to assist the transport of oil towards and out of the production wells. It is generally understood that MEOR is facilitated either by metabolites that can selectively block highpermeability zones, or by biosurfactants that are produced in situ to reduce oil viscosity and/or interfacial tension between oil-water-rock interfaces, resulting in increased mobilisation of residual oil.7-10 It has been demonstrated that microbes and nutrients injected into reservoirs were able to stimulate the in situ production of a range of products such as biosurfactants, biopolymers, acid and gas, that assisted the operation of MEOR.11-14 The overall efficiency of MEOR is believed to be directly associated with the activity of microbial and its metabolites produced within the formation microstructure.15-16 In many oil fields, long-term operations of water flooding have resulted in the heterogeneous distribution of water phase permeability, represented by either very high or very low-permeability in different zones.17 In the less permeable zone, the sweep of injected bacteria, nutrition and their metabolites is very limited. At the same time, the highpermeability zone is favourable for the fluid to pass through, thus limiting the interfacial contact with the residual oil and ultimately the efficiency of MEOR. Therefore, this poor controllability over flow has significantly affected the effect of MEOR in field applications.18-24 To tackle these problems, a range of techniques have been employed, particularly, by reducing the ineffective circulation of microorganisms and nutrition while increasing the sweep volume in the formation. One of the commonly used approaches is to use polymers for selectively plugging high-permeability zones, in order to improve the flow distribution by redirect water flow through lower permeability zones.

In the polymer-based plugging

process, chemically synthesised polymers have been commonly used.17, 25-28 For example, hydrolyzed polyacrylamide (HPAM) based gel systems have been widely used.29-30 This gel


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system has demonstrated good compatibility with a wide range of temperature and pH (from 3.3 to 12.5), and also controllability over molecular weight and viscosity. However, the gelation rate of the HPAM gels crosslinked by Cr(III) in solution has been found to be too fast to control. It is therefore necessary to effectively delay the gelation rate.31 For example, the introduction of acetate complexes of Cr(III) was able to reduce the rate of the crosslinking reaction greatly.32 Also, a modified HPAM/Cr(III) system has been found to be effective to meet different injection depth requirements, especially at the later stage of water flooding.30 Recent studies also revealed that biopolymers produced through metabolism by microorganisms, such as Xanthomonas and curdlan, can act as plugging agents.33-37 This opened a more environmentally friendly route for polymer-based plugging as biopolymers can be produced in situ within the reservoir formation during MEOR. However, there still remain technical challenges for effective application of this technology, mainly associated with the insufficient amount of biopolymers produced,

20, 38

and the degradation of the

biopolymer by the microorganisms as the carbon source. We hypothesised that a combined application of polymer-based plugging and microbial flooding can pronounce the advantages of both techniques, specifically, by increasing the flooding sweep volume through selective plugging, and also by improving the oil mobility through microbial metabolism. Currently these two techniques are mostly applied separately. To the best of our knowledge, there has been no report about their integration and application in oil field tests. Thus, the aim of the present work was to combine polymer-based plugging and microbial flooding and apply them in field tests. The well-studied HPAM/Cr(III) based gel system and a microbial strain (namely, HB3) isolated from Baolige Oilfield (located in Hebei Province, China) were employed. Laboratory based investigated was first conducted to characterise the microbial activity, the performance of the polymeric plugging system, and the compatibility of the polymer system and microorganism. Large-scale column models


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were then used to physically simulate the combined process to determine and optimise the key operational parameters, in order to assist the design and operation of the field tests.

2. MATERIALS AND METHODS 2.1. Materials. All chemicals, solvents and reagents used in this study were of analytical grade (purity > 98%) and obtained from commercial suppliers. Hydrolyzed polyacryamide (HPAM, purity 99.0%, molecular weight: 15 × 106) and chromium acetate (purity 97.0%) were purchased from Gongyi Jin Yuan Chemical Co., Ltd., China. The biochemical reagent kits were supplied by Beijing Leadman Biochemical Limited, China. Glucose, peptone, yeast extract, urea, ammonium sulphate, potassium dihydrogen phosphate, magnesium sulphate and sodium chloride (purity > 98%) were purchased from Tianjin Tian Da Chemical Factory, China. The crude oil used in the experiments was obtained from Baolige Oilfield. The crude oil sample had a density of 0.916 g/cm3 and viscosity of 0.53 Pa·s (at 38 °C). The strain used in this study was isolated from the production water of Baolige Oilfield and identified as Bacillus subtilis in our previous studies, which was named as HB3.4 The enrichment medium was developed based on growth behaviour and the composition of the formation brine. The medium used in the laboratory and oilfield tests consisted of (wt.%): glucose 1.4%, peptone 0.4%, yeast extract 0.3%, ammonium chloride 0.6%, and potassium dihydrogen phosphate 0.3%. The separation medium consisted of agar and 5(wt.)% sheep blood (with fibres being removed).


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2.2. Batch growth conditions. Batch growth experiments were performed under aerobic conditions in 100 mL LB medium at different temperatures (20-50 °C) and NaCl concentrations (w/v) 3%-21% at 200 rpm. Culture growth was determined by measuring turbidity in terms of optical density at 600 nm (OD600) using a spectrophotometer (UV-2550, SHIMADZU). The results were averages of three independent experiments. 2.3. Emulsifying activity. The emulsifying activity of fermentation broth was determined at 38 °C. The supernatant liquid was mixed with equal volume of crude oil for 2 min, and then settled at 38 °C for 24 h. The emulsification index (E24) was calculated as the ratio of the height of the emulsion layer to the total height of the mixture.39 2.4. Compatibility of HPAM/Cr(III) plugging system with strain HB3. After 24 h microbial culture, 0.2% HPAM, 0.01% cross-linker and 0.2% crosslinked polyacrylamide gel (CPAMG) were added to fermentation broth. Bacterial density and viscosity of CPAMG were then measured at regular (typically, 3 h) intervals. 2.5. Laboratory-based simulation with a large column model. Laboratory-based experiments were conducted with a full automatic core displacement device (Yangzhou Huabao Petroleum Instrument Co., Ltd.), as shown in Fig. 1. There were two unique features of this system. Firstly, it had a relatively larger size column which was 500 cm long with an inner diameter (I.D.) of 5 cm, compared to the commonly used column dimensions: length 300-500 mm and I.D. 30-40 mm

40

. Secondly, two sand-pack columns in parallel in the

system had different permeability in order to simulate formation heterogeneity.


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Figure 1. Experimental setup for laboratory-based simulation with two parallel columns.

The setup also included a pump, four accumulators, 10 sampling valves, a temperature controlled oven and a back-pressure regulator. The columns were packed with mixed silica sands (50-250 mesh) by mechanical loading, and the porosity of high and low-permeability cores were determined to be 36.2 % and 27.8%, respectively. The pore volume (PV) and the permeability of high and low-permeability cores were 3552 mL, 1029 × 10-3 µm2 and 2728 mL, 150 × 10-3 µm2, respectively. These properties are similar to the field properties of target oil reservoir. The accumulators were used for holding and injecting the crude oil, the polymer, nutrient and bacteria, while the back-pressure regulator was used to simulate the high pressure in oil reservoir. After assembly, the porosity and the permeability of the two cores were determined. The procedure of flooding tests included four stages of oil saturation, water flooding, polymer profile control and microbial flooding. Briefly, the packed columns were first saturated with brine under vacuum condition (i.e., water saturation stage). Then the cores were saturated with the crude oil from the target oilfield and aged in a temperature-controlled oven at 38 oC for a week (i.e., oil saturation stage). After that, the two cores were installed in parallel according to Fig. 1. The water flooding was performed at a flow rate of 0.2 mL/min until the high-permeability core reached a given water cut of 98.0%. Then, 0.2 PV (i.e., pore volume) of 0.2% HPAM and 0.01% cross-linker were injected into the two cores. Subsequently, water flooding was resumed until the water cut of the high-permeability core reached 98%. Following that, the microbial flooding stage was performed with 0.5 PV microbes (with a microbial density of 8 log10 cfu/mL) and nutrient (3%) slugs until no further oil was produced from the outlet of the cores. The temperature was controlled at 38 oC throughout. 2.6. Field tests. Field tests were conducted in Baolige Oilfield, involving two water injection wells (namely, B-25 and B-27) and nine oil production wells (namely, B-22, B-23, B-24, B7 ACS Paragon Plus Environment

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26, B-28, B-29, B-34, B-35 and B-57), as mapped in Fig. S1 (Supplementary Information). Initially, a total amount of 768 m3 HPAM/Cr(III) plugging fluid was injected from the two water injection wells within eight days aiming to plug the high-permeability zones, where the plugging fluid contained 0.2% Polyacrylamide and 0.01% chromium acetate. The injection displacement was controlled at 1.25-2.75 m3/h. On the basis of previous tests on polymer plugging profile control, the second stage of microbial flooding was carried out by injecting a total amount of 2100 m3 microbe and nutrient fluid over 35 days with the injection displacement of 1.2-1.5 m3/h. The bacterial density and the concentration of nutrient solution were 8 log10 cfu/mL and (wt.%) 3.0%, respectively. Then, water flooding followed with injection allocation of 35 m3/d for 7 months. During this period, a range of parameters were monitored on a monthly basis, in terms of bacterial density, oil viscosity, water cut and oil production in the produced fluid.

3. RESULTS AND DISCUSSION 3.1. The performance of strain HB3. To evaluate the adaptability of strain HB3 to the target reservoir and its effect on crude oil, the strain performance under different conditions was characterised, including growth curve, salt tolerance, viscosity reduction, and effect on emulsification. The results are shown in Fig. 2. It can be seen from the growth curves (Fig. 2A) that the screened strain HB3 grew well at all four temperature levels. The bacterial density reached a maximum in 24 h at both culture temperatures of 20 °C and 30 °C, whilst in 18 h at either 40°C or 50 °C. It was found that strain HB3 had the highest growth rate at 40 °C, that was in line with the reservoir temperature of 38 °C. Salt tolerance tests (Fig. 2B) demonstrated that salt concentration, when it was below 80.0 g/L, had insignificant effect on the growth of strain HB3. With further increase in the concentration of sodium chloride, the growth of the bacteria was inhibited significantly. It was interesting to observe that the strain still showed activity even at a salinity concentration of 210.0 g/L though at a much lower 8 ACS Paragon Plus Environment

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growth rate. The results indicated that strain HB3 had good salt resisting performance being able to meet the field salinity condition (i.e., 71.0 g/L).

0.8 20 °C

30 °C

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A

B 0.6

OD (600 nm)

OD（）（ 600 nm）

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Before 0

10

20

30 Time (h)

40

50

After

D

Figure 2. The performance of strain HB3. (A) Growth curves of HB3 at different temperatures. (B) Effect of salinity on bacterial growth at 38 °C. (C) Time-course profiles of viscosity and emulsification index E24 of strain HB3. (D) The emulsification effect of bacteria on crude oil before and after bacterial culture.

Strain HB3 also had significant effects on both viscosity and emulsification of the crude oil (Fig. 2C). When the crude oil was added to the fermentation broth for incubation, the viscosity of crude oil decreased remarkably from 0.50 Pa·s to 0.23 Pa·s (i.e., 53.7% reduction) within 24 h, and then remained stable at the low level. The trend of emulsifying index E24 value was opposite to the viscosity change. E24 increased from 0 to 83% within the first 24 h, and then stayed at the high level. The results indicated that HB3 had produced a certain amount of metabolites, likely emulsifying agents such as biosurfactants observed in the previous studies,4 and these emulsifying agents reduced the interfacial tension of oil and water.


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The emulsification effect was also clearly noticed visibly (Fig. 2D). Before microbial incubation oil and culture media remained completely separated in two phases. After 24 h culture the crude oil was well dispersed in the fermentation fluid. The emulsification effect can be beneficial to reduce the oil viscosity and oil-water mobility ratio, to increase wettability of rock, and ultimately to enhance stripping crude oil from rock surface, when applied in the oil recovery process. Overall, the findings of good adaptability of HB3 to target reservoir, together with its capabilities for viscosity reduction and emulsifying crude oil, indicated the potential of HB3 for application in MEOR. 3.2. Optimisation of HPAM/Cr(III) plugging system. The plugging performance of the HPAM/Cr(III) gelation system was evaluated with gel strength in terms of gel viscosity under different conditions in order to optimise the key parameters. Fig. 3 shows the variation of gel viscosity as a function of polymer concentration in a range of polymer concentrations over three gelation time periods. At a given polymer/cross-linker ratio (w/w) of 20:1, salinity of 15.0 g/L and temperature of 38 °C, the gel viscosity increased approximately exponentially with increasing polymer concentration for all three gelation time periods. It was found that a reaction time of 96 h allowed the strongest gel produced, reaching 6.2 Pa·s at the polymer concentration of 3.0 g/L. A longer reaction time (i.e. 720 h) showed slightly lower gel viscosity, likely due to the degradation associated with microbes and oxygen.17,

41

Nevertheless, our previous field application found that gels with a viscosity in the range of 2.5 - 4.0 Pa·s were effective for crack controlling (unpublished results). Based on that, a polymer concentration of 2.0 g/L can be expected to result in a comparable gel strength, i.e. 4.0 Pa·s for plugging applications. The effects of polymer/cross-linker ratio are illustrated in Fig. 4 on both gel viscosity and gelation time undertaken for the HPAM/Cr(III) plugging system at a polymer concentration


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of 2.0 g/L. In the previously examined ratio range of 10:1 - 30:1,42 increasing polymer/crosslinker ratio resulted in decrease in gel viscosity and, correspondingly, longer gelation time required. These trends were in line with that observed in a typical gelation process where addition of cross-linkers in a given range generally increased gel hardness.43 To obtain gels with effective viscosities in the range of 2.5 - 4.0 Pa·s , a polymer/cross-linker ratio of around 20:1 was found suitable, while the corresponding gelation time (i.e. about 6 days) was comparable to that of oil field practices.44 8.0 18 h

96 h

720 h

Viscosity (Pa·s)

6.0

4.0

2.0

0.0 0.4

0.6

0.8

1.0 1.2 Concentration (g/L)

1.5

2.0

3.0

Figure 3. Relationship between HPAM polymer concentration and gel viscosity over different gelation time periods of 18 h, 96 h, and 720 h. 5.0

250 Gelation time

4.0

200

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150

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20:1 25:1 Polymer/cross-linker ratio


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Figure 4. Effects of polymer/cross-linker ratio on gel viscosity and gelation time.

3.3. Compatibility of HPAM/Cr(III) plugging system with strain HB3. The compatibility of the HPAM/Cr(III) system with HB3 was examined by mixing the bacterial culture with different components of the gel system, whilst monitoring the change of bacterial density and also gel viscosity over a period of cultural time. The effects of polymers, cross-linkers, and the cross-linked polyacrylamide gel (CPAMG) are depicted in Fig. 5, on both bacterial density and gel viscosity. For comparison, the bacterial density in fermentation broth alone is also presented at different time point. 8.3

5.0 Fermentation broth Fermentation broth + 0.01% crosslinker Viscosity of 0.2% CPAMG

Fermentation broth + 0.2% HPAM Fermentation broth + 0.2% CPAMG

4.0

8.2 3.0

2.0

Viscostiy (Pa·s)

Bacterial density (log10 cfu/mL)

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8.1 1.0

0.0

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Time (d)

Figure 5. Compatibility of polymer-based HPAM/Cr(III) plugging system with microorganism.

As can be seen from the Fig. 5, by adding 0.2(wt.)% HPAM, 0.01(wt.)% cross-linkers, or 0.2(wt.)% CPAMG to the culture, the bacterial growth was insignificantly inhibited while the reduction in growth became slightly more notable over the time course of 30 days. Among the three compounds added, the cross-linker showed the strongest influence on microbial growth, where the bacterial density dropped from 8.11 log10 cfu/mL (Day 0) to 8.04 log10 cfu/mL (Day 30). Nevertheless, the maximum reduction in bacterial density was 2.1%, compared to the unaffected average density of 8.21 log10 cfu/mL. A similar trend in gel


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viscosity was observed, slightly dropping from 3.5 Pa·s to 3.0 Pa·s after 30-day incubation. This was also observed by Tolstikh et al.

45

where microorganisms affected the stability of

polymer gel and decreased its strength. Nevertheless, our experimental results showed that the polymer-based HPAM/Cr(III) plugging system was compatible with strain HB3 used in the MEOR process. 3.4. Laboratory-based simulation with a large column model. To simulate the process combing polymer-based plugging and microbial flooding, experiments were conducted using a laboratory-based physical model wad with two parallel sand packed large columns to simulate cores having different permeability (Fig. 1). While the water flooding, polymer injection and microbial injection steps were operated in sequence at the room temperature (25 °C), as illustrated in Fig. 6, both oil recovery efficiency and pressure drop across the column were recorded. 100

5.0

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III

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1.0

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60

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Figure 6. Laboratory-based physical simulation of polymer-assisted MEOR with two large sand pack columns in parallel.

During Step I water flooding, oil recovery from the high-permeability core was notably higher (reaching 47.1% after 30 days) than that from the low-permeability core with an oil


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recovery of 12.8% after 30 h operation. This was mainly due to the highly undistributed water flow through the two parallel cores where most of the injected water flowed through the high-permeability one. The water cut of the high-permeability core was above 98%, while unnoticeable amount of water came out of the low-permeability one. At the same time, the overall pressure drop decreased gradually from 0.8 MPa to 0.2 MPa. This can be attributed to the displacement of oil in the cores by water, as water has a much lower viscosity (1 mPa·s) than oil (530 mPa·s). When starting the injection (Step II) of the polymer-based plugging system (0.2 PV), a sharp jump of pressure from 0.2 MPa to a peak of 2.8 MPa. That was followed by a decline to 2.3 MPa when the 4-day polymer injection stopped. During this step of polymer injection, oil recovery from the high-permeability core remained relatively stable while starting to rise at the end of this step. However, increase in oil recovery occurred from the low-permeability core once the polymer injection started. The polymer injection (Step II) was followed by another water flooding (Step III). There were two distinguishing stages for oil recovery during this water flooding process; (i) increasing initially in both cores where the increase rate in the low-permeability one was higher, and (ii) reaching a plateau at the end of this step. In the high-permeability core, oil recovery increased from 47.1% to 63.2%, while in the low-permeability one from 12.8% to 47.5%, when the water cut reached 98% for both cores. The increase in oil recovery from both cores was also reflected in the step-by-step lowering (from 2.4 MPa to 2.0 MPa, and then to1.6 MPa) of the pressure drop, that was attributed to the increasing displacement of oil by water within the cores. Following the polymer-based plugging (Step II) and water flooding (Step III), microbial injection was carried out (Step IV) where 0.5 PV of mixed microbes (8 log10 cfu/mL) and nutrients (3%) solution was injected over 10 days. A noticeable change in oil recovery was


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recorded in both cores, especially over the second half of the microbial injection period. This was believed mainly due to the relatively long time operation to give sufficient time for the microbe to metabolize and interact with crude oil, based on the strain performance characterization (Fig. 2) .46-47 At the same time, a small peak of in the pressure drop profile was recorded, that was mainly due to the injection of microbial particles into the porous cores. During the final step of water flooding (Step V), i.e., polymer-assisted microbial flooding, further increase in oil recovery was achieved in both cores. Three distinguishing stages of the oil recovery profiles were also observed. In the first stage (4 days) post microbial injection, oil recoveries in both cores increased slightly, indicating an extension of the induction period. This was followed by a stage (8 days) having sharp increase in oil recovery from both cores where the increase rate was more significant in the low-permeability one. In the lowpermeability core oil recovery increased from 49.5% to 61.0%, whilst in the highpermeability one, from 67.5% to 74.0%. During the last stage starting from Day 70, oil recovery from the low-permeability core continued to increase up to 70.0% at Day 90 when the experiment stopped, while in the high-permeability one oil recovery tended to remain stable at 78.0%. The pressure drop profile during Step V corresponded to the overall oil recovery profile, but in an inverse way. It decreased when oil recovery increased, in a similar manner to that observed in the previous steps. Laboratory based physical core models have been widely used to evaluate both water flooding and MEOR.22, 48-49 The commonly used sand pack columns typically have a length of 300-500 mm and an I.D. of 30-40 mm.40 This range of column dimension and PV can limit the retention time of the injected fluid to a few hours. Therefore, it is necessary during laboratory experiments to shut the column for a period of time for polymer gelation or microbial metabolism following injection.50 However, this laboratory procedure differs from


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that operated in oilfields. Across a typical distance of a few hundred meters between injection and production wells, the injected fluid can take several dozens of days to pass through the formation. To better simulate this process, using larger column models has been suggested.51 In the present work, the employed models had significantly longer columns (length = 500 cm). At an extremely low injection flow rate of 0.2 mL/min, it required 21 days to flow through the core for a total volume of 1 PV. This retention time was sufficient for polymer gelation, according to the characterisation of the gelation process (Fig. 3) where 4-day gelation gave the highest gel viscosity. For MEOR the longer retention time also allowed adequate time for microorganism to reproduce, metabolise and interact with crude oil.51 The use of two cores having different permeability also assisted simulation more closely to the oilfield heterogeneity. In addition, it provided a powerful platform to evaluate the polymer-based plugging system, in particular, its performance across different permeability zones. By examining the cores after HPAM/Cr (III) plugging, it was found that the depths of polymer penetration and plugging in the two cores were significantly different, being 3.5 m and 0.4 m, respectively, in the high- and low- permeability cores. This was largely attributed to the pore size difference in the two cores, where larger pores in the high-permeability core allowed more and deeper flow into the porous structure. The more effective plugging in the high-permeability core resulted in redirection and redistribution of flow through the lowpermeability one in which more significant increase in oil recovery was achieved (Fig. 6). The oil recovery enhancement was further pronounced after microbial injection, especially in the low-permeability core (Fig. 6). This was largely due to more residual oil remaining in the core before microbial flooding, and also more microbial flow into this zone as a result of selective plugging.52-54


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3.5. Field tests. The field tests of polymer-assisted MEOR were carried out from March 20 to October 25, 2015 in Baolige Oilfield, following a primary water flooding process. During the polymer-based plugging HPAM/Cr(III) was injected for deep profile control through two injection wells of B-25 and B-27. The effect of plugging on water injection profile was evaluated by quantifying water absorption in a control radius of 45-65 m at a range of depths (i.e., 1070-1120 m). Water injection profiles are compared in Fig. S2 (Supplementary Information) before and after polymer-based plugging for both wells. In both B-25 and B-27 wells there were only two and three layers, respectively, taking significant amounts of water before polymer-based profile control. Most of water was taken at the depth of 1090 m, absorbing 89.5% and 62.8% of the injection brine in B-25 and B-27, respectively. In contrast, after profile control B-25 had five absorption layers while B-27 had six. Moreover, the distribution of water absorption, in the range of 6.0% to 34.5%, was more uniform across more layers. This was clearly indicative that the polymer-based plugging had effective deep profile control through redirection and redistribution of flow from the original high-permeability layers to their neighbouring ones. The monitoring data during the field tests are presented in Fig. 7 including bacterial density, oil viscosity, water cut, and daily oil production from the nine oil wells investigated. Four operation steps were carried out, namely, primary water flooding, polymer injection, microbes and nutrients injection, and polymer-assisted microbial flooding. Except that the daily oil production shows the sum of nine wells, the other parameters are the average of the monitoring results of nine wells. The results for each oil production well are summarised in Table S1 (Supplementary Information).


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Figure 7. Monitoring results of polymer-assisted MEOR in field tests, through 4 steps: (I) primary water flooding, (II) polymer injection, (III) microbes and nutrients injection, and (IV) polymer-assisted microbial flooding. Except that the daily oil production shows the sum of 9 wells, the other parameters are the average of the monitoring results of 9 wells.

It can be seen that the bacterial density in the formation was about 3 log10 cfu/mL (over Steps I & II) before microbial injection. It began to rise gradually during the injection Step III for 1 month. In the water flooding Step IV, there was initially a sharp jump in bacterial density and eventually reached the highest level of 6 log10 cfu/mL after 2-month water flooding. The bacterial density remained at the high level for about 3 months, that was followed by a gradual decline to 4.5 log10 cfu/mL after 6-month water flooding. The decline was believed mainly due to the nutrient consumption during the subsequent water flooding after 4-month water flooding. Even the relatively lower level of bacterial density (i.e., 4.5 log10 cfu/mL) was still significantly higher than that before microbial injection (i.e., 3 log10 cfu/mL).51 As also seen from the bacterial density profile, it took 3 months to reach the 18 ACS Paragon Plus Environment

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maximal level after bacterial injection, that was notably longer than the results, typically 1 to 2 months, that we obtained in other similar well groups using microbial flooding alone without polymer-based. The results indicated that the profile control by polymer-based plugging were effective in prolonging retention time of bacteria in the reservoir, up to seven months. The viscosity profile of crude oil corresponded well to the change of bacterial density but in an inverse manner with a slight time lag. The viscosity started to decreased when the water flooding began, and reached the lowest level after about 5-month water flowing, showing a reduction of 58.8%. This demonstrated the significant effect of bacteria on crude oil to reduce its viscosity, one of the main key contributing factors for MEOR.5, 8-9, 37 The slight time lag observed was also likely due to the time needed for microorganism to metabolise and interact with crude oil.51 The water cut decreased from 88% to 74% during the polymer and bacterial injection Steps II & III, and then remained relatively stable during most of the water flooding Step IV, except for a small dip for 1 month. The reason for the dip was unclear which may need further investigation. Nevertheless, it further confirmed the effect of profile control by polymer-based plugging that improved the water flooding efficiency. The oil recovery started to increase along both polymer and bacterial injection Steps II & III. That was extended in the water flooding Step IV and reached the highest level of 95 t from the nine wells, following the bacterial density maximum, and remained the high production level for about 3 months. That was followed by a gradual decline as shown in the bacterial density profile, mainly due to the consumption of the nutrient.51, 55 At the end of November 2015 when the field tests ended, the cumulative oil increment in nine wells was 3486 t with an overall EOR of 57.6%. That was more significant than that of either polymerassisted water flooding or microbial enhanced water flooding alone. As a result, the present field tests confirmed the advantage of combining polymer-based plugging for profile control 19 ACS Paragon Plus Environment

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and microbial enhanced water flooding as an effective polymer-assisted MEOR technique. This provided a promising route to solve the problem associated with low efficiency of water flooding that may be caused by the heterogeneity of the reservoir and the poor physical properties of the crude oil. As a complex process involving both chemical and biological systems and their interactions with multiphase (water/oil) flow, there is still room to improve in order to achieve high process efficiency. For example, the polymer-based plugging system with a higher concentration of polymer can further improve the deep profile control and, in turn, the microbial retention time and sweep volume. Also, in the present field tests only one run of bacterial and nutrient injection was carried out, and the bacterial density started to decline after water flooding for about five months (Fig. 7). Therefore, maintaining bacterial density at a high level for longer time can be expected by running additional nutrient injections at optimized intervals.

4. CONCLUSIONS In the present study, a polymer-assisted microbial enhanced oil recovery (MEOR) process was investigated. The main conclusions could be drawn as follows. (1) Strain HB3, isolated from the test oilfield, was found to have the highest growth rate around the reservoir temperature of 38 °C, across a wide salinity concentration range. It also showed capability to reduce the crude oil viscosity (at 53.7% reduction) and emulsifying oil (reaching an emulsifying index E24 reduction of 83%). (2) Optimization of the polymeric HPAM/Cr(III) plugging system was established, which was also confirmed to be compatible with the microbial system. (3) Laboratory-based simulation demonstrated that the polymer-based profile control can selectively plug high-permeability zones. Compared to water flooding, about 30.9%


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and 57.2% of oil recovery by polymer-assisted MEOR were obtained in high and lowpermeability cores, respectively. (4) The field tests confirmed the significant improvement of deep profile control by polymer-based plugging. An ultimate oil recovery of 57.6% and a cumulative oil increment of 3486 t from nine wells over the 7-month field were achieved. (5) To conclude, it was demonstrated that the combination of polymer-based plugging and microbial flooding provided a promising technological route for MEOR applications, especially for highly heterogeneous reservoirs. For further improvement more detailed studies are required, e.g., on the selection of polymer concentrations and the introduction of additional nutrient injections at optimized intervals.

■ AUTHOR INFORMATION Corresponding Author *E-mail: [email protected], [email protected]. ORCID Xun-Li Zhang: 0000-0002-0174-2159 Notes The authors declare no competing financial interest.

■ ACKNOWLEDGEMENTS This work was supported by the National Natural Science Foundation of China (Grant Nos. 21376190

and

21676215),

Xi’an

Science

and

Technology

Project

(Grant

No.

2017081CG/RC044 (XASY001)) and the Graduate Innovation and Practice Skills Foundation of Xi'an Shiyou University (Grant Nos. YCS17211012, YCS17211014 and YCS17211015).


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