Open Access
Issue
Oil Gas Sci. Technol. – Rev. IFP Energies nouvelles
Volume 73, 2018
Article Number 55
Number of page(s) 8
DOI https://doi.org/10.2516/ogst/2018059
Published online 20 November 2018

© M. Zhou et al., published by IFP Energies nouvelles, 2018

Licence Creative Commons
This is an Open Access article distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/4.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

1 Introduction

At present, high water-cut and high salinities are issues in the many oilfields in China, such as the Zhongyuan Oilfield, the Changqing Oilfield and the Tarim Oilfield [1]. Therefore, Enhanced Oil Recovery (EOR) technology is of significant interest and one of the most important drivers for developing oil and gas fields [2, 3]. Chemical flooding is an important the mature technique of EOR, which includes polymer flooding, surfactant flooding, foam flooding, alkaline flooding and combinational flooding [46]. Polymers have been used successfully in EOR for quite a long time. The polymers as flooding agent play an important role in chemical flooding for tertiary oil recovery [7, 8]. Polymer solutions, compared with water, show non-Newtonian rheological behavior, such as shear thinning and viscoelastic behavior. Adding a polymer to water increases the viscosity of the aqueous solution to obtain a better mobility ratio. However, a certain amount of crude oil still remains in the oil reservoir [9].

Foam not only has a certain ability to expand the sweep volume, but also can improve the displacement efficiency [10]. Foam is becoming increasingly attractive as a mobility profile control agent [11]. Nevertheless, the foam is a kind of unstable thermodynamic system and a spontaneous process reduces the energy of the system. From the above analysis, it can be concluded that the foam is an unstable system, which determines relative stability of the foam itself [1214].

Cross-linked polymer spheres have the characteristics of relative thermal stability, great water absorbency, controllable size, swelling and deformation, which clearly differs from preformed gel particles [15, 16]. The nanospheres have a good injection and migration and can plug high permeability layer in the low permeability reservoir because they can deform under pressure and across oil bearing reservoirs to control deep profiles [17]. As a result, they can change the direction of the injected water for the ultimate purpose of enhancing oil recovery [18].

The Composite Index (FCI) of conventional foam is very low in the high salinity solution because the foaming volume is small and the half-life is remarkably short [19]. To solve this problem, the P(MSt-co-MMA) nanospheres were prepared by emulsion polymerization at first, then the three phase foam system consisting of surfactant, P(MSt-co-MMA) nanospheres and polymer KYPAM-II was prepared in this paper. The three phase foam system cannot only improve the stability of the foam, but also improve the foaming property of the foam. It can achieve the higher effectiveness for EOR.

2 Experiment

2.1 Materials

Methyl Styrene (MSt), Methyl Methacrylate (MMA), Divinyl Benzene (DVB), sulphobetaine surfactant (dodecyl dimethyl betaine surfactant) and Ammonium Persulfate (APS) were purchased from Chengdu Kelong Chemical Reagents Corporation (PR China) and were used in the tests without further purification. DOSZ as emulsifier was supplied by the Nanjing Chemlin Chemical Industry Co., Ltd. Hydrolysis polyacrylamide KYPAM-II was purchased from Beijing Heng Ju Co., Ltd. The Ingredients of formation brine used in the experiment are listed in Table 1. Oil with a viscosity of 10 mPa s and a density of 0.82 g/cm3 at 75 °C was obtained from Y201 well in Yanchang Oilfield, PR China.

Table 1.

Composition of formation brine.

2.2 Instrument

A Fourier Transform Infrared Spectroscope (Nicolet 6700) and a Scanning Electron Microscope (SEM) ZEISS EV0 MA15, produced by Carl Zeiss Microscopy Co., Ltd, Germany, and laser particle size analyzer (LPSA) produced by Malvern Co., Ltd (UK) were used for the investigation. The Thermo Gravimetric Analyzer (TGA) was purchased from Switzerland. A multi-function core displacement device was purchased from Hai’an County Oil Scientific Instrument Co., Ltd, China. An OWC-9360 high speed stirring apparatus was obtained from Shenyang Institute of Aeronautical Engineering, PR China.

2.3 Preparation of polymer nanospheres via emulsion polymerization

The poly (MSt-MMA) nanospheres were prepared by emulsion polymerization. First, 20 wt% MSt monomer and 5 wt% MMA monomer were added in 250 mL three-neck flask equipped with a nitrogen inlet. 0.30% Divinyl Benzene (DVB) crosslinking agent, 2.0 wt% Disodium 4-Dodecyl-2,4′-Oxydiben Zenesulfonate (DOZS) emulsifier and 2.0 wt% (NH4)2S2O8 initiator were added into the three-neck flask in turn. The internal temperature then was raised in a linear manner from room temperature to 75 °C over 20 min and then kept at 75 °C for 8 h. The cross-linked P(MSt-co-MMA) nanospheres were obtained.

2.4 Optimization of components of the three phase foam

Anionic surfactants have the advantage of wide sourcing, good foaming performance and low cost, but their stability performance was poor. By contrast, both polymer solutions and polymer nanospheres have greater foam stability performance. The sulphobetaine surfactant (dodecyl dimethyl betaine surfactant) as foaming agent, KYPAM-II and poly(MSt-MMA) nanospheres as foam stabilizer, and formation brine were weighed according to the specified ratios using an electronic balance. They were thoroughly mixed in the beaker (500 mL) and the foaming solutions were obtained. The foam was prepared by stirring at a 4000 rpm rotation rate for 60 s in Warning Blender. The generated foam was poured into 1000 mL measuring cylinder. Original foaming volume (Vmax) was recorded. The time (half-life t1/2) was recorded when the foam coalesced and reduced to half of foaming volume. According to FCI, the foaming performance and foam stability were determined. The better foam stability is and the bigger foaming volume is, the larger FCI value is:(1)where equation (1), FCI is defined as the foam composite index; Vmax is the maximal of foam volume, that is, original foaming volume; t1/2 is the half-life period of the foam.

2.5 Evaluation of temperature and salt resistance

According to the range analysis of the orthogonal test array, the experimental data showed that the primary and secondary factors influencing FCI could be obtained. The foaming ability and half-life of foam generated by the optimal parameter combination was measured at different temperatures and salinities.

2.6 Oil displacement efficiency

A core oil-displacement simulation test of the three phase foam was undertaken, as shown in Figure 1. The sizes of artificial cores were measured using a Vernier caliper. Then, the core was put into the thermostat and it was saturated by the formation water. The porosity and permeability of the core were calculated according to the test results. The core displacement experiment was carried out at 75 °C and the outlet pressure was atmospheric pressure.

thumbnail Fig. 1.

A flow diagram of the core displacement apparatus.

3 Results and discussion

3.1 Structure characterization

An example infrared spectrum of poly (MSt-MMA) nanospheres was determined by FTIR, as was shown in Figure 2. The absorption peak at 3014 cm−1 belonged to C=C stretching vibration of the benzene ring skeleton. The absorption peaks at 1596 cm−1, 1498 cm−1 and 1457 cm−1 belonged to the benzene skeleton characteristic peaks and the peaks at 762 cm−1 and 701 cm−1 belonged to the mono-substituted benzene peaks. The peak at 1735 cm−1 belonged to ester characteristic peak and the peak at 2941 cm−1 methyl vibration peak. The double bond characteristic absorption peak did not appear at 1660 cm−1, which indicates that the double bond has been opened. Thus, the crosslinking copolymer poly (MSt-MMA) nanospheres was obtained.

thumbnail Fig. 2.

Infrared spectra of the poly (MSt-MMA) nanospheres.

3.2 LPSA analysis

The size of poly (MSt-MMA) nanospheres was determined by LPSA, and the results were illustrated in Figure 3. The crosslinking copolymer nanospheres had outstanding mono-dispersion and the average diameter was about 80 nm.

thumbnail Fig. 3.

Size distribution of the poly (MSt-MMA) nanospheres.

3.3 SEM analysis

The morphology and size of poly (MSt-MMA) nanospheres were characterized by SEM, as was shown in Figure 4. The nanosphere was spherical, and the average particle diameter also was about 80 nm and as same as the diameter by LPSA.

thumbnail Fig. 4.

SEM of poly (MSt-MMA) nanospheres.

3.4 TG analysis

The TG curve of the poly (MSt-MMA) nanospheres is shown in Figure 5. The poly (MSt-MMA) nanospheres had very small weight loss of 1.2% at 183 °C. The poly (MSt-MMA) nanospheres had significant weight loss of 6.4% at 375 °C. The major weight loss of the poly (MSt-MMA) nanospheres at 452 °C (92.4%). Therefore, the poly (MSt-MMA) nanospheres had a decomposition temperature of 375 °C. The result indicated that poly (MSt-MMA) nanospheres had good thermal stability.

thumbnail Fig. 5.

TG analysis curve of poly(MSt-MMA) nanospheres.

3.5 Orthogonal experiment of preparing three phase foam

The factors and levels of the orthogonal matrix tests are listed in Table 2, and the test results and analyses are summarized in Table 3. The test data revealed that the main effect factors on the performance of the foam, in turn, are the polymer, then surfactant and nanospheres. The maximum value of Foam Composite Index (FCI) was 710 235 mL s in the nine experiments when the foam solution consisted of 0.10 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant (dodecyl dimethyl betaine surfactant) and 0.04 wt% poly(MSt-MMA) nanospheres. The optimum formula was 0.12 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant, 0.04 wt% poly (MSt-MMA) nanospheres by orthogonal experiment and the FCI of the optimum formula was 855 625 mL s, as was used in the following tests.

Table 2.

Factors and levels of orthogonal experiment.

Table 3.

Results and analysis of orthogonal experiment.

3.6 Assessment of properties

(1) Temperature tolerance

The volume and half-life of the optimum foam formula, at different temperatures, are shown in Figure 6. With the increase of the temperature, the volume of the three phase foam reduced very little, because dodecyl dimethyl betaine surfactant had good temperature tolerance and the changes of temperature almost effect the hydrophile-lipophile balance and surface intension. But the half-life of the three phase foam always decreased significantly, because the viscosity of the system reduced obviously and the evaporation of water and gas diffusion were accelerated when the temperature increased, which led to liquid film rapid thinning. By means of the calculation using equation (1), the FCIs of the three phase foams were 484 537 mL s at 50 °C and 175 500 mL s at 90 °C, respectively.

thumbnail Fig. 6.

Temperature tolerance test of the optimum formula (0.12 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant, 0.04 wt% poly(MSt-MMA) nanospheres, CNaCl = 8 × 104 mg/L).

(2) Salinity tolerance

As was displayed in Figure 7, when the salinity (NaCl) was in the range of 1 × 104 ~ 5 × 104 mg/L, with the increase of salinity, the foam volume expanded and remained stable while the half-life declined and at last FCI remained constant. When the electrolyte was added, the diffusion double layers were compressed and the repulsive force between hydrophilic ions weakened, so the surfactant molecules arranged more closely on the surface and the foam was more stable. However, with the increase in the electrolyte concentration, the charged double layer bubble film was repulsed to avoid further weakening stable discharge and foam stability was decreased.

thumbnail Fig. 7.

Salinity tolerance test of the optimum formula (0.12 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant, 0.04 wt% poly(MSt-MMA) nanospheres, 45 °C).

In summary, the KYPAM-II and the poly(MSt-MMA) nanospheres, as important factors, maintain a longer foam half-life than do foaming systems with foaming agent. The FCI of foam systems at high temperature is smaller than those at low temperature. In consequence, the foam solution can be used for high temperature reservoirs with high salinity in the injected water wells.

(3) Aging stability

Dependent on the formation permeability, injection rate and well spacing, the foam flooding system often stays in the formation to last several months or years during the displacement process. If oxygen and metals are dissolved in solution, high temperature will promote the degradation of surfactants and polymer. Therefore, its aging stability is very important to the pilot application. We investigated the aging stability for 160 days. As was showed in Figure 8, under reservoir conditions, FCI changed very little, and the system didn’t appear to precipitate and floater. It illustrated that the properties of three phase foam flooding system could keep stability during the displacing period.

thumbnail Fig. 8.

FCI versus aging time (0.12 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant, 0.04 wt% poly(MSt-MMA) nanospheres, formation brine, 75 °C).

(4) Foam apparent viscosity

Pressure drop in foam coreflood was determined and foam apparent viscosity was calculated by equation (2) in literature (Heller, 1994; Ma et al., 2013) as follows:(2)where equation (2), μ – foam apparent viscosity (cP); n – power law index, in general, n = 1; ΔP – pressure difference between core inlet and outlet (Psi); R – inner radius of the core (inch); Q – volumetric flow rate under the experimental temperature and pressure (cm3/min); L – length of the core (foot).

Basic parameters of the core in the experiment were length 0.2664 foot, diameter 0.9855 inch (d = 2 R), weight 96.68 g, core permeability 8.67 × 10−3 μm2 and porosity 9.22%. Flow rate was 0.8 cm3/min and gas liquid ratio was 3:1. The pressure drop in the system was recorded every 30 s. Pressure drop 2540.5 Psi was obtained in steady-state during the displacement.

A typical foam apparent viscosity history is described in the injection experiment, as is shown in Figure 9. The foam apparent viscosity reached a steady state after about 1.1 Total Pore Volumes (TPV). A lot of white tiny uniformed foam flowed out the core outlet, which proved that foam was created in the coreflood experiments. The sudden pressure changes at 1.1 and 3.2 TPV were due to the operation of refilling injectants. The steady-state foam apparent viscosity (about 205 cp) for 3:1 gas liquid ratio was obtained by averaging the plateau viscosities.

thumbnail Fig. 9.

Typical foam apparent viscosity history of injection versus total pore volume. (Flow rate 0.8 cc/min, gas liquid ratio 3:1, formation brine, 75 °C.)

Pressure difference and apparent viscosity quickly increased with the increase of injected total pore volume and the value of pressure difference, and apparent viscosity of three phase foam flooding were more than that of water flooding when injected total pore volume was same, which suggested that foam was constantly created in the coreflood experiments.

As was seen from Figure 9, with the increase of injected total pore volume, the resistance gradually increased, and the apparent viscosity of the foam increased sharply, which indicated that the amounts of the three phase foam increased gradually. Foam in the porous media continued to produce and increase. When the injection total pore volume reached 1.1 PV, the produced bubble amounts and burst bubble amounts reached a dynamic balance, so that the resistance increased to the maximum. When the injected total pore volume was greater than 1.1 PV, the apparent viscosity of the foam almost kept constant and the average apparent viscosity was close to 205 mpa s, that was, the foam reached a stable dynamic state.

(5) Resistance coefficient and residual resistance coefficient

Resistance coefficient (Fr) is a technical index to evaluate the foam system improving mobility ratio. The resistance coefficient is defined as the ratio of the differential pressure of profile control agent flow through the core to that of water flow through the same core at same flow rate. Equation (3) is as follows:(3)where equation (3), △PG is velocity displacement pressure of profile control agent; △Pw is velocity differential pressure of certain brine.

It is called the residual resistance coefficient (Frr) to reflect the ability of the foam flooding to reduce the permeability of porous media. Its value is equal to the ratio of the permeability of brine phase after the foam flooding is injected into the core to the permeability of brine phase before the foam is injected into the core. Equation (4) is as follows:(4)where equation (4), KP is the permeability of brine phase after injected the foam; △Kb is the permeability of brine phase before injected the foam.

After brine was saturated by flow rate 0.1 mL/min, 200 mg/L, foam was injected 3 PV into the two sand-packed. Then 50 PV brine was injected. Initial brine flooding pressure, the pressure after injecting 3 PV foam and the pressure after injecting 50 PV brine flooding were noted, respectively. The results of resistance coefficient and residual resistance coefficient of the three phase foam were calculated and were shown in Table 4.

Table 4.

Resistance coefficient and residual resistance coefficient.

Resistance coefficient of low permeability core was more than that of high permeability core, but both of residual resistance coefficients were small and similar. The experiment results indicated that the three phase foam had good profile control ability, and was low damage to the low permeability layer.

(6) Displacement oil efficiency

Physical properties of the sandstone cores and flooding efficiency of single core by using three phase foam are shown in Tables 5 and 6, respectively. Foam flooding recovers additionally 13.5 wt% and 18.6 wt% oil in high permeability core and low permeability core, respectively, when the difference of permeability is approximately 5. The difference of permeability (Kmn) is the ratio of the maximum permeability (Kmax) to the minimum permeability(Kmin), showing the distribution and difference in degree of permeability. The average displacement efficiency of three phase foam is 16.1 wt%.

Table 5.

Physical properties of the sandstone cores.

Table 6.

Summary flooding tests in core displacement device.

(7) Profile control

Physical properties of the sandstone cores and flooding efficiency of double core by using three phase foam are shown in Tables 7 and 8, respectively. The double parallel core displacement experiments were performed. The experiments were carried out at approximately 75 °C and the flow rate 0.2 mL/min during saturating brine, saturating oil, water flooding for each core, respectively. Then the double cores were paralleled with the same entrance and the same exit. The foam were injected from entrance, and flowed through two cores. Finally, the foam flowed out from exit. Yanchang crude oil with viscosity of 8.3 mPa s at 75 °C and formation brine were used in the experiment. Throughout the experiment, the cores were first saturated with Yanchang crude oil and formation brine was injected until the water-cut was 98%; then 0.5 PV three phase foam was injected; finally, then only 10 PV formation brine was injected.

Table 7.

Physical properties of the sandstone cores.

Table 8.

Summary flooding tests in core displacement device.

The difference between the permeability of the high and low permeable layers is about five times in turn, too. Three phase foam flooding efficiencies were 18.2 wt% and 27.3 wt% in high permeability core and low permeability core, respectively. Average EOR was 21.7 wt%, which is more than that of two phase foam (15.9 wt%) in the literature [19]. More subsequent fluid flowed into the low permeable layers after the foam was injected. The experiment results showed the three phase foam have good profile control.

4 Results of pilot test

From May 2015 to September 2015, a pilot test of three phase foam flooding was performed in the Y201 well group and the Y204 well group. The pilot test achieved initial success. The field injection foam pressure was between 14.5 and 17.5 MPa. In Y201 well, normal injection pressure was about 15.7 MPa, and in Y204 well, normal injection pressure was about 17.1 MPa, injection pressures of the two wells were lower than the scheme of limits 19.5 MPa. Two well groups were beginning to bear fruit from June 2015, and production liquid amount increased slightly, then water-cut decreased greatly and oil production increased a lot. From June 1 to September 25, cumulative injected foam liquid was 1252.5 m3, the cumulative gas injection 142 550.7 m3, conversion of underground foam volume 4415.6 m3, a total of increased oil of corresponding two well groups was 567.9 t. We estimated preliminarily that the ratio of input and output of the two well groups was 1:2.72, which showed that recovery oil of the three phase foam flooding was considerable.

5 Conclusion

The crosslinked polymer nanospheres as a foam stabilizing agent were prepared by emulsion polymerization with MSt and MMA as monomers, DVB as crosslinker, OP-10 as emulsifier and APS as initiator. The poly(MSt-MMA) nanospheres were characterized by FT-IR, LPSA, SEM and TGA. The average particle of the crosslinked polymer nanospheres was 80 nm. The optimum formulation of the three phase foam was screened by the orthogonal experiment. The temperature and salt tolerance of three phase foam were very good. Flooding oil experiment showed that the average displacement efficiency of three phase foam system was 16.1 wt% in single core experiments and 21.7 wt% in double core experiments. Resistance coefficient of low permeability core was more than that of high permeability core, but their residual resistance coefficients were small and similar, which indicated that the three phase foam had good profile control ability and generated low damage to the low permeability layer for extra-low permeability reservoirs. Thus, three phase foam flooding has great prospects for EOR in extra-low permeability reservoirs.

Acknowledgments

The work was supported by key project of opening experiments of Southwest Petroleum University-2017 (No.x151514kcl16).

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All Tables

Table 1.

Composition of formation brine.

Table 2.

Factors and levels of orthogonal experiment.

Table 3.

Results and analysis of orthogonal experiment.

Table 4.

Resistance coefficient and residual resistance coefficient.

Table 5.

Physical properties of the sandstone cores.

Table 6.

Summary flooding tests in core displacement device.

Table 7.

Physical properties of the sandstone cores.

Table 8.

Summary flooding tests in core displacement device.

All Figures

thumbnail Fig. 1.

A flow diagram of the core displacement apparatus.

In the text
thumbnail Fig. 2.

Infrared spectra of the poly (MSt-MMA) nanospheres.

In the text
thumbnail Fig. 3.

Size distribution of the poly (MSt-MMA) nanospheres.

In the text
thumbnail Fig. 4.

SEM of poly (MSt-MMA) nanospheres.

In the text
thumbnail Fig. 5.

TG analysis curve of poly(MSt-MMA) nanospheres.

In the text
thumbnail Fig. 6.

Temperature tolerance test of the optimum formula (0.12 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant, 0.04 wt% poly(MSt-MMA) nanospheres, CNaCl = 8 × 104 mg/L).

In the text
thumbnail Fig. 7.

Salinity tolerance test of the optimum formula (0.12 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant, 0.04 wt% poly(MSt-MMA) nanospheres, 45 °C).

In the text
thumbnail Fig. 8.

FCI versus aging time (0.12 wt% KYPAM-II, 0.10 wt% sulphobetaine surfactant, 0.04 wt% poly(MSt-MMA) nanospheres, formation brine, 75 °C).

In the text
thumbnail Fig. 9.

Typical foam apparent viscosity history of injection versus total pore volume. (Flow rate 0.8 cc/min, gas liquid ratio 3:1, formation brine, 75 °C.)

In the text

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