Synergistic Mechanism of Hydrolyzed Polyacrylamide Enhanced

Article Cite This: Energy Fuels XXXX, XXX, XXX−XXX

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Synergistic Mechanism of Hydrolyzed Polyacrylamide Enhanced Branched-Preformed Particle Gel for Enhanced Oil Recovery in Mature Oilfields Hong He,*,†,‡ Jingyu Fu,‡ Hui Zhao,‡ Fuqing Yuan,§ Lanlei Guo,§ Zongyang Li,§ Xiang Wang,‡ and Hao Peng‡

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†

Hubei Cooperative Innovation Center of Unconventional Oil and Gas and ‡College of Petroleum Engineering, Yangtze University, Wuhan 430100, Hubei, China § Research Institute of Exploration and Development of Shengli Oilfield, SINOPEC, Dongying, China ABSTRACT: Branched-preformed particle gel (B-PPG) is a novel agent for EOR application in mature reservoirs. To improve the enhanced oil recovery (EOR) performance of B-PPG, the heterogeneous combination flooding system composed of B-PPG, hydrolyzed polyacrylamide (HPAM), and surfactant was proposed. However, the synergistic mechanism of B-PPG and HPAM still remains unclear. Here, a series of experiments were performed to study the viscosities of HPAM, B-PPG, and mixture of HPAM and B-PPG, evaluate the suspension stability of B-PPG and mixture of HPAM and B-PPG, to investigate the propagation behavior of HPAM, B-PPG, and a mixture of HPAM and B-PPG through porous media, and to study the EOR performance of HPAM, B-PPG, and a mixture of HPAM and B-PPG in heterogeneous reservoirs by performing parallel sand pack flooding experiments. Results show that the suspension stability of B-PPG can be improved by adding polymer due to the increase in viscosity. The higher the HPAM concentration is, the higher viscosity of mixture of HPAM and B-PPG suspension and the better the suspension stability is. Due to the lubrication and increased viscosity effect of the polymer, compared with the B-PPG suspension, the HPAM enhanced B-PPG suspension can be more easily injected into the porous media and can propagate through porous media. The propagation behavior of HPAM enhanced B-PPG through porous media is achieved by blocking, deforming, and passing through the pore throat. EOR performance results in a heterogeneous reservoir demonstrate that HPAM enhanced B-PPG flooding shows better sweep efficiency improvement ability and recovers more remaining oil left unswept in the low permeability zones.

1. INTRODUCTION With the rapid increase of fossil fuels consumption, it is of vital importance to produce more crude oil from oil reservoirs. The oil recovery process from the reservoir is usually implemented in three main periods: primary recovery, secondary recovery, and tertiary recovery.1,2 The primary recovery is obtained by utilizing natural displacement energy present in the reservoir. Depending on the driving mechanism, the natural displacement energy sources can be categorized into four groups: rock and fluid expansion, solution gas, water influx, and gravity drainage. When the reservoir is depleted after primary production has reached its economic limit, the secondary recovery can usually be implemented, which is obtained by injection water or an immiscible gas. However, it is about 60−70% of the remaining oil in the reservoir that can still not be recovered after primary and secondary recovery stages. Thus, tertiary recovery or enhanced oil recovery (EOR) methods have been proposed to recover more remaining oil that cannot be recovered after primary and secondary recovery stages.3 Different EOR technologies have been used to recover oil from different reservoirs, such as thermal EOR,4,5 chemical flooding,6 miscible gas flooding,7 nanofluid flooding,8 foam flooding,9,10 and so on. For conventional reservoirs especially when the reservoir is depleted after primary production, water flooding is a widely used technique to increase oil production by injecting water to maintain the reservoir pressure. However, due to the © XXXX American Chemical Society

permeability contrast between different layers in seriously heterogeneous mature reservoirs, the injection water preferentially flows into the high permeability layers, and a large proportion of remaining oil is unrecovered in low permeability layers. Thus, many mature waterfloods suffer from water breakthrough and undesired water production, leading to poor sweep efficiency and low oil recovery. Hence, many techniques have been developed to reduce water production and improve sweep efficiency and oil recovery. Conformance control has been widely used to reduce water production by chemical plugging and mechanical plugging methods.11−13 Polymer gel treatments have been proven as an economical and effective water control technique to enhance oil recovery in many oilfields.14−18 According to the different preparation methods and gelation conditions, the polymer gel can be categorized as in situ cross-linked polymer gel and preformed particle gel. The in situ cross-linked polymer gel is formed under reservoir conditions by injecting the gelant solution including polymer and cross-linker into the reservoir. During the gelant solution injection process, due to shear effects from pump lines and porous media, formation water dilution effect and adsorption effect, the cross-linking reaction of gelant solution Received: May 11, 2018 Revised: October 9, 2018 Published: October 23, 2018 A

DOI: 10.1021/acs.energyfuels.8b01661 Energy Fuels XXXX, XXX, XXX−XXX

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propagation behavior of HPAM, B-PPG, and a mixture of HPAM and B-PPG through porous media, and to study the EOR performance of HPAM, B-PPG, and a mixture of HPAM and B-PPG in heterogeneous reservoirs.

will become more complicated under reservoir conditions. The in situ gelation behavior during flow in reservoir is totally different from the bulk gelation behavior under bottle test conditions.19,20 Thus, it is difficult to control the cross-linking reaction to obtain the proper gelation time and gel strength of cross-linked polymer gel. Moreover, the in situ cross-linked polymer gel may have an impact on damaging the low permeability oil zone. To overcome the disadvantages of the cross-linked polymer gel mentioned above, the preformed particle gel is obtained by controlling the cross-linking reaction that occurs under the surface conditions. Because of its advantages in controlling cross-linking reactions, the preformed particle gel has been extensively studied and applied. Thus, in recent years, different types of preformed particle gels have been developed by different preparation methods. The current available preformed particle gels can be categorized into four groups including dispersed particle gels, preformed particle gels, bright water and pH-sensitive microgels. The dispersed particle gel is prepared by using a cross-linked polymer under high shearing.21−25 According to the particle size, micrometer-sized or millimeter-sized preformed particle gels are obtained by using acrylamide as monomer, cross-linker, initiator, and other additives.26−29 The bright water known as temperature sensitive polymer microgels are submicron gel particles.30−32 When preformed particle gel (PPG) is injected into a reservoir, it can swell in formation brines under the reservoir temperature. And the swelling ratio of PPG is dependent on the salinity and temperature. For the pH sensitive microgels, as the pH increases, the gel will adsorb water and swell. The swelling ratio can be as high as 10000.33−35 Due to the unique properties of good temperature resistance, salt tolerance, and plugging performance, preformed particle gels have been applied in high permeability mature reservoirs or fracture reservoirs. However, due to the poor injection performance, bad suspension stability, and in-depth propagation ability, it is not suitable for the preformed particle gels to apply in low permeability reservoirs.36 In view of the shortcomings of preformed particle gel, a novel branched-preformed particle gel (B-PPG) with linear branched chains has been proposed and applied in the Shengli oilfield.37,38 The B-PPG suspension shows good viscoelastic properties and fluid diversion ability.39,40 Combining the conformance control ability of B-PPG and oil displacement ability of surfactant, the heterogeneous combination flooding system composed of hydrolyzed polyacrylamide (HPAM), B-PPG, and surfactant has been proposed and recognized as an effective EOR method after polymer flooding. On the basis of good laboratory results, a pilot test was conducted in the Shengli oilfield and high incremental oil recovery was achieved.37 Although the heterogeneous combination flooding has been applied in the Shengli oilfield successfully, there is still a lack of knowledge and clarification of the EOR mechanisms. Previous studies showed that the B-PPG can improve the viscoelastic property and surfactant can improve oil displacement efficiency, whereas the synergistic mechanism of B-PPG and HPAM still remains unclear. The interaction mechanisms between PPG and surfactant have been studied by numerical simulation and laboratory experiments.41,42 However, as far as we know, little research has been conducted on the synergistic mechanism of BPPG and HPAM for enhanced oil recovery. In this study, to clarify the synergistic mechanism, laboratory experiments were performed to investigate the viscosities of HPAM, B-PPG, and a mixture of HPAM and B-PPG, to evaluate the suspension stability of mixture of HPAM and B-PPG, investigate the

2. EXPERIMENTAL SECTION 2.1. Materials. B-PPG was provided in particle form by the Shengli oilfield. The B-PPG can absorb water and swell in simulated formation brine. Figure 1 shows the morphology of B-PPG before and after

Figure 1. Morphology of B-PPG before and after swelling in simulated formation brine: (a) before swelling; (b) after swelling. swelling in formation brine. The particle size distribution of B-PPG after swelling was measured by using a Beckman Coulter multisizer, shown in Figure 2. The average particle diameter of the B-PPG after

Figure 2. Device for particle size distribution measurement. swelling in simulated formation brine is 240 μm. The partially hydrolyzed polyacrylamide (HPAM) was an anionic polymer provided by the Shengli oilfield, of which the average molecular weight is about 2.6 × 107. The crude oil was also provided by the Shengli oilfield, of which the viscosity was 68.5 mPa·s at 70 °C. The salinity of simulated formation brine is 7101 mg·L−1. Table 1 illustrates the ion concentrations of simulated formation brine.

Table 1. Ionic Composition and Concentration of Simulated Formation Brine ionic composition concentration/mg·L

−1

Na+

Ca2+

Mg2+

Cl−

HCO3−

2502

82

25

3502

990

2.2. Methods. 2.2.1. B-PPG and Mixture of HPAM and B-PPG Suspension Systems Preparation. The B-PPG and mixture of HPAM and B-PPG suspension systems used in the experiments were prepared as follows: (1) according to the ionic composition of simulated formation brine, the brine solution was prepared by adding the precalculated amounts of NaCl, CaCl2, MgCl2, and NaHCO3 into the distilled water under the mechanical stirring at a temperature of 25 °C; (2) then precalculated amounts of HPAM and B-PPG were added into B


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where SR is the sedimentation ratio at a certain time, Vt is the sedimentation volume of B-PPG particle at a given time, and Vf is the final sedimentation volume of B-PPG particle. 2.2.4. Flow and Flooding Experiments. 2.2.4.1. Preparation of Sand Pack and Property Measurement. The sand pack used for flow and flooding experiments was prepared according to the following steps: (1) First, quartz sand with different particle sizes was sieved by a sieve shaker with different mesh sizes. Then the coarse sand and fine sand with different mesh size were obtained by means of sieving. According to the results of the multiple test results, the high permeability sand packs was prepared by using coarse sand (40−60 mesh) to simulate the high permeability layer in the reservoir. The low permeability sand pack was prepared by using the fine sand (the mass ratio of 160 mesh sand and 80−100 mesh sand is 1:2) to simulate the low permeability layer in the reservoir. (2) Second, the sand pack was placed in vertical position under the effect of vibration. Then the sand was added into the sand pack after adding the simulated formation brine, which can ensure the pore of sand pack was completely saturated by formation brine. Moreover, it is necessary to pack the sand pack during the preparation process. The amount of saturated formation brine was the pore volume of sand pack, and the porosity of sand pack was measured. The permeability of sand pack was measured by simulated formation brine injection and calculated according to Darcy’s law.44 2.2.4.2. Propagation Behavior Test. The propagation behavior studies of HPAM, B-PPG, and a mixture of HPAM and B-PPG through porous media was carried out on sand packs (Φ2.5 cm × 30 cm) with multipoint pressure taps. Figure 5 depicts a schematic diagram of propagation behavior test. The experimental procedure of propagation behavior test was as follows: (1) The simulated formation brine was continuously injected into the sand pack at the injection rate of 1.0 mL·min−1 until the pressure drop was stable. The permeability of sand pack was calculated by Darcy’s law. (2) Then pore volumes of HPAM, B-PPG, and a mixture of polymer and B-PPG were injected into the sand packs, and the multipoint pressure was measured by a pressure acquisition system at different times. (3) Then after slug injection of HPAM, B-PPG, and a mixture of polymer and B-PPG, the subsequent water flooding was conducted again at the same injection rate. The resistance factor (Fr) is a very important parameter in understanding the propagation behavior in the reservoir. The residual resistance factor (Frr) is used to understand the conformance control ability. Taking the B-PPG for example, the resistance factor of B-PPG is defined as the pressure drop during the B-PPG injection process divided by the pressure drop during brine injection. The prerequisite for the definition is that the injection rate is the same during the B-PPG injection and brine injection process. The equation is shown below:45,46

the prepared brine solution slowly by mechanical stirring; (3) after stirring for 8.0 h, the B-PPG suspension and HPAM solutions were obtained; (4) then the mixture of HPAM and B-PPG suspension was prepared by mixing predetermined amounts of prepared high concentration B-PPG suspension and HPAM solution under mechanical stirring. 2.2.2. Viscosity Measurement. The viscosities of HPAM, B-PPG, and a mixture of HPAM and B-PPG were studied by using a Brookfield rotational viscometer (model DV-II). The viscosities of all samples were conducted at 30 °C. 2.2.3. Suspension Stability Evaluation. The suspension stability of B-PPG, a mixture of B-PPG and HPAM with various concentrations was studied by means of direct visual observation method and quantitative calculation method. On the basis of direct visual observation, the sedimentation ratio was used to evaluate the suspension stability in the quantitative calculation method. The sedimentation ratio is defined as the sedimentation volume divided by final sedimentation volume.43 The higher the sedimentation ratio was, the worse the suspension stability was. The experimental procedures were as follows: (1) The suspension systems of B-PPG, the mixture of B-PPG and HPAM were obtained by the mentioned preparation method. (2) Then the swollen B-PPG particles were filtered out from the suspension system and dyed with the blue gouache color. The gouache color was purchased from Shanghai SIIC Marie Painting Materials Co., Ltd., shown in Figure 3. Then the dyed swollen

Figure 3. Blue gouache color used for dying the swollen B-PPG particle. B-PPG particles were put back into the suspension system. (3) Different mixture suspensions with dyed B-PPG and polymer were prepared and then poured into the tube. (4) Then the suspensions were allowed to rest for 120 min at ambient temperature. (5) Finally, the sedimentation volume of B-PPG was recorded, and the sedimentation ratio was calculated at different times. Because the swollen B-PPG particles were dyed by the blue gouache color, the sedimentation of blue materials can reflect the sedimentation of B-PPG, and thus the sedimentation ratio of B-PPG can be calculated. Figure 4 shows the schematic diagram of sedimentation of swollen BPPG particles. The sedimentation ratio at a certain time is expressed by the following equation: V sedimentation ratio (SR)t = t Vf

Fr =

ΔPB ‐ PPG ΔPbrine

(2)

where the Fr is the resistance factor of B-PPG, ΔPB‑PPG is the pressure drop during B-PPG injection, and ΔPbrine is the pressure drop during brine injection. The residual resistance factor of B-PPG is defined as the brine pressure drop before B-PPG placement divided by the brine pressure after B-PPG placement. The prerequisite for the definition is that the brine injection rate is the same before and after B-PPG placement. The equation is shown below:

(1)

Frr =

(ΔPbrine)After (ΔPbrine)Before

(3)

where the Frr is the residual resistance factor of B-PPG, (ΔPbrine)After is the brine pressure drop after B-PPG placement, and (ΔPbrine)Before is the brine pressure drop before B-PPG placement. 2.2.4.3. EOR Performance Evaluation. The EOR performance of HPAM, B-PPG, and a mixture of HPAM and B-PPG in heterogeneous reservoirs was evaluated by flooding experiments using the parallel sand pack model. Figure 6 shows the schematic diagram of EOR performance evaluation in heterogeneous reservoirs. The experimental

Figure 4. Schematic diagram of sedimentation of swollen B-PPG particle. C


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Figure 5. Schematic diagram of propagation behavior test through porous media.

Figure 6. Schematic diagram of EOR performance evaluation in heterogeneous reservoirs. procedures were described in detail as follows: (1) First, high and low permeability sand packs with the required porosity and permeability were prepared. (2) Then the crude oil was continuously injected into the sand pack at the injection rate of 0.1 mL·min−1 until only oil was produced from the outlet end of sand pack. Then according to the amount of water produced and pore volume, the initial oil saturation of sand pack can be calculated. (3) Water flooding period: after the sand pack was aged for 48 h at the reservoir temperature of 70 °C, the simulated formation brine was injected into the sand pack to displace oil until the water cut of produced liquid was 95%. The water injection rate is 1.0 mL·min−1. (3) Chemical flooding and subsequent water flooding period: After water flooding, then 0.3 PV chemical slug (HPAM, BPPG, mixture of polymer and B-PPG) was injected into the sand pack, and then subsequent water flooding was carried out until the water cut of produced liquid was 95% again. During the process of water flooding, chemical flooding and subsequent water flooding, the produced liquid volume, the produced oil volume, and the injection pressure were recorded at different time intervals. Then the changes of fractional flow, water cut, and oil recovery versus injected pore volumes were obtained. The fraction flows of the high and low permeability sand pack at a certain times can be calculated according to the following equations:47

fhigh (%) =

Q high Q high + Q low

flow (%) =

Q low Q high + Q low

× 100% (5)

where f high is the fraction flow of the high permeability sand pack, f low is the fraction flow of the low permeability sand pack, Qhigh is the produced liquid volume of high permeability sand pack, and Qlow is the produced liquid volume of low permeability sand pack.

3. RESULTS AND DISCUSSION 3.1. Viscosity Properties of HPAM, B-PPG, and a Mixture of HPAM and B-PPG. The viscosities of HPAM, BPPG, and a mixture of HPAM and B-PPG were studied by using a Brookfield rotational viscometer (model DV-II). The viscosities of all samples were performed at 30 °C. Then the viscosities of HPAM, B-PPG, a and mixture of HPAM and BPPG at 30 °C were depicted in Figure 7. The viscosity of mixture of HPAM and B-PPG is the highest, followed by the viscosity of polymer, and the viscosity of B-PPG is the least. Moreover, the viscosity of a mixture of HPAM and BPPG increases with the increase of HPAM concentration. 3.2. Suspension Stability of B-PPG and a Mixture of HPAM and B-PPG. On the basis of the viscosity properties study, B-PPG has viscosity property. However, due to the

× 100% (4) D


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HPAM with various concentrations was investigated to figure out the effect of polymer on B-PPG suspension stability. Figure 8 shows the suspension states of a mixture of HPAM and B-PPG versus rest time. It is noted that as the time lengthens, the suspension states of mixture of B-PPG and HPAM with different concentrations are different. When the HPAM concentration is 500 mg·L−1, most of B-PPG settles completely in 10 min, and only a small amount of smaller particles are still suspended. When the HPAM concentration is 1000 mg·L−1, the B-PPG settles completely in 40 min. When the HPAM concentration is 1500 mg·L−1, the B-PPG settles completely in 100 min. When the HPAM concentration is 2000 mg·L−1, B-PPG still does not settle completely in 200 min, and a small amount of smaller particles are still suspended. Thus, it can be noted that the sedimentation time increases with the increase of HPAM concentration. Besides, for the particle size and distribution is not uniform, the large particle gel settles faster than the small particle gel. Moreover, the similar sedimentation trend can be observed for the B-PPG suspension. Then the sedimentation ratio of B-PPG and a mixture of BPPG and HPAM with various concentrations versus time is illustrated in Figure 9. In Figure 9a, as the time extends, the sedimentation ratio increases sharply and then slows down until it is stable. Under the same sedimentation ratio, the higher the B-PPG concentration, the more time needed to settle completely. Although the suspension stability of B-PPG can be enhanced by increasing the concentration, the suspension stability of B-PPG without HPAM is worse than that of a mixture of HPAM and BPPG suspension. In Figure 9b, as the time extends, the sedimentation ratio increases sharply and then slows down until it is stable. As the size of B-PPG is uneven, the large size of B-PPG settles faster than the small size of B-PPG. Under the same sedimentation ratio, the higher the HPAM concentration, the more time needed to settle completely. The explanation of the phenomenon is as follows: With the increase of HPAM concentration, the viscosity of a mixture of HPAM and B-PPG suspension increases. By adding polymer, the suspension stability of B-PPG can be improved due to the increase in viscosity. The higher HPAM concentration is, the higher viscosity of mixture of

Figure 7. Viscosities of HPAM, B-PPG, and a mixture of HPAM and BPPG: (a) HPAM, B-PPG; (b) a mixture of HPAM and B-PPG.

heterogeneous phase of B-PPG suspension, the sedimentation of B-PPG is still prone to occur during injection due to lower viscosity and bad suspension stability. Thus, it is necessary to study the suspension stability of B-PPG, which can affect the injectivity and propagation behavior. In this study, the suspension stability of B-PPG and a mixture of B-PPG and

Figure 8. Suspension states of mixture of B-PPG and HPAM with various concentrations as a function of time: From left to right the HPAM concentration are 500 mg·L−1, 1000 mg·L−1, 1500 mg·L−1, and 2000 mg·L−1; (a) 1 min; (b) 10 min; (c) 30 min; (d) 40 min; (e) 100 min; (f) 200 min. E


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Figure 9. Sedimentation ratio versus time for B-PPG without polymer and the mixture of B-PPG and polymer with various concentrations: (a) B-PPG; (b) mixture of B-PPG and polymer with different concentrations.

HPAM and B-PPG suspension and the better the suspension stability is. 3.3. Propagation Behavior of HPAM, B-PPG, and HPAM Enhanced B-PPG. The propagation behavior HPAM, B-PPG, and a mixture of HPAM and B-PPG through porous media was investigated by conducting sand pack flow experiments to figure out the effect of polymer on B-PPG propagation behavior. The porosity and permeability of sand packs used for experiments are illustrated in Table 2.

Figure 10. Pressure change across the sand pack versus injected pore volumes: (a) HPAM; (b) B-PPG; (c) B-PPG + HPAM.

Table 2. Porosity and Permeability of Sand Packs Used for Propagation Experiments flooding fluid −1

1000 mg·L HPAM 1500 mg·L−1 B-PPG 1000 mg·L−1 HPAM+ 1500 mg·L−1 B-PPG

stable with the increase of injected pore volume. According to the calculation method of resistance factor, the resistance factor (Fr) of the first segment, the second segment, and third segment is 25.2, 14.8, and 15.7, respectively, shown in Table 3. Moreover, at the stage of subsequent water flooding, according to the calculation method of residual resistance factor, the residual resistance factor (Frr) of the first segment, the second segment and third segment is 3.4, 3.2, and 2.1, respectively. The results indicates that HPAM can propagate through the porous media. In Figure 10b, during the process of B-PPG injection, as the injected pore volume increases, the injection pressure (P1) fluctuates, while the pressure of the second and third segment (P2 and P3) of sand pack changes slightly. Similarly, the resistance factor (Fr) of the first segment is 716, but the resistance factor (Fr) of the second and third segment is 1.3 and 1.0, respectively. Moreover, at the stage of subsequent water flooding, before clean the sand face of sand pack, as the injected pore volume increases, the injection pressure (P1) fluctuates, but

permeability/μm2 porosity/% 3.64 4.05 3.84

41.4 40.8 42.8

Figure 10 illustrates the pressure drop across the sand pack versus injected pore volumes during different flooding periods. According to the evaluation method of resistance factor and residual resistance factor, the resistance factor and residual resistance factor of HPAM injection, B-PPG injection, and a mixture of HPAM and B-PPG injection at different segments of sand pack are illustrated in Table 3. In Figure 10a, during the process of polymer injection, the injection pressure (P1), the pressure of the second and third segment (P2 and P3) of sand pack increases first and then is F


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Table 3. Resistance Factor and Residual Resistance Factor of B-PPG Injection and a Mixture of HPAM and B-PPG Injection at Different Segments of Sand Pack Fr flooding fluid

Frr

Fr1

Fr2

Fr3

sand face treatment after slug injection

Frr1

Frr2

Frr3

1000 mg·L−1 HPAM 1500 mg·L−1 B-PPG

25.2 716

24.8 1.3

15.7 1.0

1000 mg·L−1 HPAM + 1500 mg·L−1B-PPG

254

unclean sand face before cleaning sand face after cleaning sand face after cleaning sand face

3.4 489 1.3 39.2

3.2 1.2 1.1 32.9

2.1 1.0 1.0 1.7

192

77

Table 4. Properties of the Sand Packs for EOR Performance Evaluation flooding fluid

slug/PV

sand pack type

permeability/μm2

permeability contrast

porosity/%

soi/%

HPAM

0.3 0.3

1000 mg·L−1 HPAM + 1500 mg·L−1B-PPG

0.3

4.12 0.85 4.05 0.82 3.69 0.79

4.85

1500 mg·L−1 B-PPG

high permeability low permeability high permeability low permeability high permeability low permeability

47.6 42.8 47.6 42.8 44.8 40.8

81.4 68.3 78.6 74.6 86.4 78.3

1000 mg·L

−1

4.94 4.67

flooding experiments using parallel sand pack model. In all tests, the concentration of B-PPG and HPAM was 1500 mg·L−1 and 1000 mg·L−1 respectively. Table 4 illustrates the properties of the sand packs for EOR performance evaluation. 3.4.1. Fractional Flow Curves. Figure 11 shows the change of fractional flows of high and low permeability sand pack at different flooding stages including the initial water flooding, HPAM slug injection, B-PPG slug injection or mixture of B-PPG and HPAM slug injection and subsequent water flooding. The changing trends of fractional flow curves for HPAM injection, BPPG injection, or a mixture of HPAM and B-PPG injection are similar:

the pressure of the second and third segment (P2 and P3) of sand pack is nearly the same as that of the water injection before BPPG placement. After cleaning of the sand face of sand pack, the injection pressure (P1) decreases, and the pressure of the second and third segment (P2 and P3) of sand pack also is nearly the same as that of the water injection before B-PPG placement. Thus, before cleaning of the sand face of sand pack, the residual resistance factor (Frr) of the first segment, the second segment and third segment is 489, 1.2, and 1.0, respectively, whereas after cleaning of the sand face of sand pack, the residual resistance factor (Frr) of the first segment decreases from 489 to 1.3, but the Frr of second and third segment is 1.1 and 1.0, respectively. The results indicate that no B-PPG passed through the second and third segment of sand pack. The explanation of the phenomenon is as follows: Because of the low viscosity and bad suspension stability of B-PPG, the sedimentation of B-PPG can be prone to occur, and most of B-PPG accumulates at the inlet end of sand pack, which results in plugging and the increase of injection pressure. When the pressure increases to a certain value, the deformation and breaking of B-PPG occur, and only a small part of B-PPG can be injected into porous media, but the B-PPG can only propagate nearby the sand pack. In Figure 10c, as the injected pore volume increases, the injection pressure (P1) and the pressure of the second and third segment (P2 and P3) of sand pack fluctuate, but the pressure change reflects a stable trend. Similarly, the resistance factor (Fr) of the first segment, the second segment, and third segment is 254, 192, and 77, respectively, shown in Table 3. Moreover, at the stage of subsequent water flooding, after cleaning of the sand face, the Frr of the first segment, the second segment and third segment is 39.2, 32.9, and 1.7, respectively. The results indicates that mixture of HPAM and B-PPG can propagate through the porous media. The explanation of the trend is as follows: Because of the lubrication and increased viscosity effect of polymer, the HPAM enhanced B-PPG suspension is more easily injected and propagated in porous media. Meanwhile, a few of BPPG deposits on the pore surface, and the propagation behaviors of mixture of HPAM and B-PPG through porous media are migration in pores, plugging, deforming, and passing through the throat. 3.4. EOR Performance in Heterogeneous Reservoir. The EOR performance of HPAM, B-PPG, and a mixture of HPAM and B-PPG in heterogeneous reservoirs was evaluated by

(1) At the stage of the initial water flooding, due to the parallel sand pack model with permeability contrast, a large proportion of injected water enters into the high permeability layer. Thus, the fractional flow of high permeability layer is more than 95%, while that of the low permeability layer is less than 5%. (2) At the stage of HPAM flooding, B-PPG flooding, or mixture of HPAM and B-PPG flooding, due to the existence of water flow channels in the high permeability layer after water flooding, the slug of HPAM, B-PPG, and a mixture of HPAM and B-PPG injection can preferentially enter into the high permeability and plug the water flow channels. Thus, the fractional flow of the high permeability layer decreases, while that of low permeability layer increases. (3) At the stage of subsequent water flooding, for the slug of B-PPG and HPAM injection, as the slug of mixture of BPPG and HPAM can propagate in the sand packs, the fractional flows of high and low permeability sand pack fluctuate. Whereas for the slug of B-PPG injection, as the B-PPG cannot propagate in sand packs, the factional flow of high permeability sand pack increases, while that of low permeability sand pack decreases. It should be mentioned that the fractional flows before and after the injection of HPAM slug, B-PPG slug, or a mixture of HPAM and B-PPG slug are different. The changes in fractional flows during different flooding stages indicate that HPAM enhanced B-PPG flooding shows better conformance control ability than B-PPG flooding and HPAM flooding in a heterogeneous reservoir. G


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Figure 12. Changes of pressure drop versus injected pore volumes during different flooding stages.

phenomenon can be attributed to the higher viscosity and better propagation behavior of the slug of B-PPG and HPAM injection. Thus, the changes in fractional flows and pressure drop during different flooding stages indicate that HPAM enhanced B-PPG flooding shows better conformance control ability than B-PPG flooding in a heterogeneous reservoir. 3.4.2. Enhanced Oil Recovery. Figure 13 shows the cumulative oil recovery and water cut versus injected pore volume curves at different flooding stages. The cumulative oil recovery of high and low permeability sand pack versus injected pore volume curves at different flooding stages is plotted in Figure 14. On the basis of the results of cumulative oil recovery curves, the oil recovery of HPAM, B-PPG, and HPAM enhanced B-PPG at different flooding stages is summarized in Table 5 and Figure 15. According to the cumulative oil recovery curves, the analysis of flooding characteristics at different stages is listed below: (1) Water flooding stage: Because of the reservoir heterogeneity, the injection water can preferentially enter into the high permeability sand pack, which results in a large percentage of remaining oil in low permeability sand pack unrecovered. Thus, the oil recovery of high permeability sand pack is higher than that of low permeability sand pack after water flooding. (2) Chemical flooding and subsequent water flooding stage: The purpose of HPAM, B-PPG injection, or mixture of HPAM and B-PPG injection is to improve the sweep efficiency by diverting the injection water to the low permeability sand pack. Table 5 and Figure 15 show that oil recovery of the low permeability pack increases by HPAM injection, B-PPG injection, or a mixture of HPAM and B-PPG injection and the subsequent water flooding. It can be noted that the incremental oil recovery of low permeability pack for B-PPG injection is lower than that of low permeability pack for a mixture of HPAM and B-PPG injection. Meanwhile, the total incremental oil recovery of B-PPG injection is lower than that of a mixture of HPAM and B-PPG injection. 3.5. Potential EOR Mechanism of Mixture of HPAM and B-PPG in Heterogeneous Reservoirs. On the basis of the above experimental results, Figure 16 depicts a potential EOR mechanism for HPAM enhanced B-PPG flooding in heterogeneous reservoirs. As reservoirs become mature, due to the reservoir heterogeneity, the injected water preferentially enters into the high permeability zone. Once water channeling

Figure 11. Fractional flow curves of different flooding fluids versus injected pore volumes: (a) HPAM flooding; (b) B-PPG flooding; (c) BPPG + HPAM flooding.

To further clarify the result, the changes of pressure drop versus injected pore volumes during different flooding stages are shown in Figure 12. In Figure 12, the changing trends of pressure drop curves for HPAM injection, B-PPG injection, or a mixture of HPAM and B-PPG injection are similar. During the stage of HPAM flooding, B-PPG flooding, or a mixture of HPAM and B-PPG flooding, the pressure drop of HPAM enhanced polymer flooding is higher than that of B-PPG flooding and polymer flooding. Moreover, at the stage of subsequent water flooding, the pressure drop of HPAM enhanced polymer flooding is higher than that of B-PPG flooding and polymer flooding. This H


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Energy & Fuels

Figure 13. Cumulative oil recovery and water cut of the parallel-sand pack flooding test: (a) HPAM flooding; (b) B-PPG flooding; (c) BPPG + HPAM flooding.

Figure 14. Cumulative oil recovery and water cut of the parallel-sand pack flooding test: (a) HPAM flooding; (b) B-PPG flooding; (c) BPPG + HPAM flooding.

occurs, more unswept remaining oil will be trapped in the low permeability zone (Figure 16b). Thus, it is crucial to improve sweep efficiency and recover remaining oil after water flooding. Then the slug of mixture of HPAM and B-PPG is injected into the reservoir. Due to the existence of a high permeability channel, the slug can preferentially enter into the high permeability zone and propagate through the porous media (Figure 16c). At the stage of subsequent water flooding, the BPPG blocks the pore throat and diverts the subsequent injection water into the low permeability zone. Moreover, the B-PPG can continuously block, deform, and pass through the pore throat to

achieve the fluid diversion and improve sweep efficiency (Figure 16d).

4. CONCLUSIONS In this study, a series of experiments have been performed to study the viscosity property, suspension stability, propagation behavior, and EOR performance of HPAM, B-PPG, and a mixture of HPAM and B-PPG. Then the synergistic mechanism of HPAM enhanced B-PPG for enhanced oil recovery was determined. The following conclusions can be drawn: I


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Energy & Fuels Table 5. Summary of the Oil Recovery Results for Different Flooding Fluids in Heterogeneous Reservoirs

(1) By adding polymer, the suspension stability of B-PPG can be improved due to the increase in viscosity. The higher the HPAM concentration, the higher viscosity of a mixture of HPAM and B-PPG suspension and the better the suspension stability is. (2) Due to the lubrication and increased viscosity effect of polymer, compared with the B-PPG suspension, the HPAM enhanced B-PPG suspension can be more easily injected into the porous media and can propagate through porous media. The propagation behavior of HPAM enhanced B-PPG through porous media can be achieved by blocking, deforming, and passing through the pore throat. (3) The changes in fractional flows and pressure drop during different flooding stages indicate that HPAM enhanced BPPG flooding shows better conformance control ability than B-PPG flooding in a heterogeneous reservoir. This phenomenon can be attributed to the higher viscosity and better propagation behavior of the slug of B-PPG and HPAM injection. Thus, the injection of a mixture of HPAM and B-PPG suspension can achieve better fluid diversion and higher sweep efficiency than that of B-PPG injection. (4) EOR performance results in a heterogeneous reservoir demonstrate that the total incremental oil recovery of BPPG injection is lower than that of mixture of HPAM and B-PPG injection in heterogeneous reservoir, which can indicate that HPAM enhanced B-PPG flooding shows better sweep efficiency improvement ability and recovers more remaining oil left unswept in the low permeability zones.

enhanced oil recovery/%OOIP flooding fluid HPAM

B-PPG

B-PPG + HPAM

sand pack type

water flooding

subsequent water flooding

incremental recovery

high permeability low permeability total high permeability low permeability total high permeability low permeability total

49.4

66.5

17.1

8.8

20.7

11.9

32.0 51.3

46.8 73.5

14.8 22.2

7.0

22.2

15.2

31.5 50.4

50.8 81.3

19.3 30.9

4.3

24.7

20.7

29.5

55.7

26.2

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AUTHOR INFORMATION

Corresponding Author

*E-mail: [email protected]. Tel.: +86-189-9560-8643. ORCID

Figure 15. Incremental oil recovery for different flooding fluids in heterogeneous reservoirs.

Hong He: 0000-0002-7798-2749 Notes

The authors declare no competing financial interest.

Figure 16. Proposed EOR mechanism of HPAM enhanced B-PPG: (a) initial distribution of oil in reservoir; (b) water channel occurs; (c) injection of slug of a mixture of HPAM and B-PPG; (d) subsequent water injection after a mixture of HPAM and B-PPG flooding. J


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ACKNOWLEDGMENTS This work was supported by National Natural Science Foundation of China (Project No. 51604037) and Research Institute of Exploration and Development of Shengli Oilfield.

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Synergistic Mechanism of Hydrolyzed Polyacrylamide Enhanced

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