Enhanced Oil Recovery Study of a New Mobility Control System on the

Jan 30, 2018 - Enhanced Oil Recovery Study of a New Mobility Control System on the Dynamic Imbibition in a Tight Oil Fracture Network Model...
0 downloads 0 Views 1MB Size
Download PDF
Article pubs.acs.org/EF

Cite This: Energy Fuels 2018, 32, 2908−2915

Enhanced Oil Recovery Study of a New Mobility Control System on the Dynamic Imbibition in a Tight Oil Fracture Network Model Mingwei Zhao,† Haonan He,† Caili Dai,*,† Yongpeng Sun,† Yanchao Fang,† Yifei Liu,† Qing You,‡ Guang Zhao,† and Yining Wu† †

School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong 266580, China School of Energy Resources, China University of Geosciences, Beijing 100083, China

‡

S Supporting Information *

ABSTRACT: Aiming at increasing the recovery in tight oil reservoir with fractures, a new kind of mobility control system with function of imbibition (MCSI) was prepared with dispersed particle gel (DPG) and surfactant. The dynamic imbibition can effectively control the mobility ratio in a tight oil fracture network and increase oil recovery. Based on the characteristics of tight oil reservoir fractures, the preparation method of a multiple fracture network model was established. The prepared fracture network model has the characteristics of controllable fracture length, width, and height. The MCSI system can reduce the oil− water interfacial tension to 10−2 mN/m. It features low viscosity, strengthening water wet, thus promoting the imbibition effect. Dynamic imbibition tests of the multiple fracture network model show that the MCSI system has higher oil recovery than each single component. At the same time, the subsequent water flooding after soaking also has the function of enhancing oil recovery. The effects of fluid type, flow rate, fracture width, and matrix fracture network model type on oil recovery of MCSI are clarified.

1. INTRODUCTION Tight oil refers to the oil formed in tight reservoirs.1,2 In China, tight oil accounts for 2/5 of the recoverable oil resources, which has broad exploration prospects. In recent years, the development of tight oil resources in China has made a major breakthrough. About 5−10 billion tons of reserves were found in the Ordos basin, and it is preliminarily estimated that the amount of geological reserve is more than 20 billion tons.3 Compared with conventional reservoirs, tight oil reservoirs have the characteristics of poor physical properties, such as low matrix permeability and low porosity, where formation needs to be stimulated to generate fractures to obtain oil and gas flow.4−6 At present, segmented multifracture large scale volume fracturing technology is mainly used, which forces the tight reservoir to form complex fracture networks intertwined by hydraulic fractures and natural fractures, thus providing channels for tight oil output.7 The matrix−fracture structure of a tight oil reservoir is formed after fracturing, in which the matrix is so tight that it is difficult to use conventional water flooding to displace oil into the fracture network.8 On the one hand, the imbibition effect caused by capillary forces in the microscale pore throat is very important to the production of crude oil. On the other hand, due to strong heterogeneity of reservoir between matrix and fracture network, fractures are likely to become the flowing channels of water and oil. The channels of water and gas in fractures lead to poor sweep efficiency in the matrix, so the control of the fluid mobility in fractures is also very important. At present, with unique characteristics and advantages, the chemical method has become one of the most important technologies to enhance oil recovery,9−11 especially ASP flooding which consists of alkali, polymer, and surfactant and SP flooding based on surfactant and polymer. Polymer can increase the sweep efficiency by decreasing mobility ratio. © 2018 American Chemical Society

Surfactant can reduce the oil/water interfacial tension and improve the effective use of crude oil. The interfacial tension between oil and water can be reduced to 0.011−0.015 mN/m, and the recovery can reach 14−24%.13−17 In addition, the wettability in the matrix can be changed through imbibition, which is also regarded as the mechanism of surfactant flooding process.12 Alkali can enhance the mobility control ability of polymer by emulsification. However, in the actual field test, polymer is easily affected by the shearing within equipment and geological conditions, whose viscosity decreases greatly. The presence of alkali may reduce the viscosity of polymer, which leads to formation damage, wellbore scaling, and emulsification of crude oil. Controlling the mobility of displacing fluid is still a great challenge. The dispersed particle gel (DPG) with the functions of mobility ratio modification and conformance control has received a large amount of attentions in the recent years. DPG can adjust the flow profile effectively and make liquid flow to the low permeable layers to recover crude oil.18−20 The oil recovery increment can reach 46% and the subsequent water flooding recovery can be increased by 3.3%, which mean the oil recovery of low permeability reservoir is greatly improved.21−26 So if mobility control system is combined with the imbibition function of surfactant, can larger oil recovery be obtained? Based on this design, in this work, mobility control system is formulated by DPG and surfactant. The mobility control system with function of imbibition (MCSI) can not only improve the sweep efficiency of the crude oil in fractures, but also enhance effective use of crude oil in the core matrix through imbibition effect. As reported before, the recovery in the matrix−fracture network can be increased.27−29 Received: October 27, 2017 Revised: January 23, 2018 Published: January 30, 2018 2908

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915

Article

Energy & Fuels

the colloid mill was considered as DPG solution. The average particle diameter of the DPG was 1.3 μm measured by Laser particle size distribution instrument (Bettersize2000, Baite instrument Co., Ltd., China). 2.2.2. Viscosity Measurement. Brookfield Viscometer (PVS Model, Brookfield, America) was used to carry out the viscosity measurement of the MCSI at the temperature of 80 °C, with viscometer 0 rotor (6 r/min). About 20 mL samples were injected into the sleeve. After 15 min under constant temperature, the viscosity value was measured and recorded by the viscometer. Then, the samples were put into the oven at 80 °C for aging. The viscosities of 0.1 wt % MCSI (0.1 wt % DPG + 0.1 wt % THSB), 0.1 wt % DPG solution, and 0.1 wt % THSB surfactant solution were measured with aging time, respectively. 2.2.3. Interfacial Tension (IFT) Measurement. Surfactant solutions, 0.1 wt % MSCI, oil, and 0.1 wt % THSB, were prepared. The interfacial tensions between oil and MCSI and oil and 0.1 wt % THSB surfactant solution were observed at 80 °C by interfacial tensiometer (TX500C, Kono Company, America), respectively. The rotational speed was 6000 rpm, and the interfacial tension was calculated from Vonnegut approximation as reported previously.36 The IFT values were recorded when it became stable for 30+ min. Fluids were put into the oven at 80 °C for aging. The interfacial tension between oil and 0.1 wt % MCSI and oil and 0.1 wt % surfactant solution were measured with aging time, respectively. 2.2.4. Wettability Alteration Measurement. The ability of MCSI to change the rock wettability was measured by the goniometer (JC2000D2, Zhongchen Co., Ltd., China). Formation rock was imitated by water-wet quartz plates. Initial contact angles on quartz plates were measured with oil drop first. Then, quartz plates were put into 0.1 wt % MCSI and 0.1 wt % THSB surfactant solution, respectively. Next, oil drop was applied on the quartz plate and the contact angle was measured. After fluids were aging in the oven at 80 °C for 5, 10, and 15 days, the wettability alteration degrees on the quartz plates were measured, respectively.37−39 2.2.5. Manufacturing of Matrix Fracture Network Model. The preparation method for the matrix fracture network model mainly includes the following steps. First, a cylindrical core was selected and cut vertically into several core sections with same length by core cutting machine. Second, the core sections were cut horizontally in a certain proportion and two small core blocks were obtained. Then, these small core blocks were stacked naturally according to their positions before cutting. Use the same method to place other core sections and put them together horizontally, so that the matrix fracture network model was formed. The diagrams of actual and physical model can be seen in Figure 1. During dynamic imbibition experiment, the fracture width can be controlled by applying appropriate confining pressure and axial pressure. The relationship between confining pressure, axial pressure, and effective fracture width is built up below:

However, it is not clear how does the dynamic imbibition of the system impacts the oil recovery in the matrix−fracture network. In addition, creating the matrix−fracture network model is a key piece of the work, so the fracture model needs to be designed first.30−33 Taking tight cores as the basic object, the preparation methods in the lab are mainly classified into four types: volume fracturing method, artificial splitting method, vaporization method, and salt ion dissolving method. Fracture network structures formed by the volume fracturing method and artificial splitting method are irregular and cannot be repeated. In the procession of the vaporization method, there are a lot of gases produced that cannot volatilize thoroughly, which affect the flowing of fluids. The salt ion dissolution method is based on the dissolution of salt ions and is only applied to high permeability cores. Therefore, it is necessary to design and set up a new matrix fracture network model preparation method for tight cores. In this manuscript, a matrix fracture network model was designed and prepared first. This method has the advantages of controllable fracture width, good replicability, and high operability. MCSI was constructed by DPG and a kind of surfactant.34,35 Basic properties of the system were characterized. In addition, various factors which impact on the oil recovery on MCSI in the matrix fracture model were evaluated systematically, such as fluid type, fluid concentration, fluid flow rate, fracture width, etc.

2. EXPERIMENTAL SECTION 2.1. Materials. MCSI was composed of DPG, surfactant, and brine. Nonionic polyacrylamide (PAM) was used to prepare DPG, with degree of hydrolysis 3.31% and average molecular weight of 9 650 000 g/mol provided by Yuguang Co., Ltd. Dongying, China. The crosslinker of phenolic resin was purchased from Fanghua Co., Ltd. Dongying, China. Tetradecyl hydroxypropyl sulfonyl betaine (THSB), as surfactant, was bought from Shanghai Connaught Industry Co., Ltd. China. The inorganic salts, including NaCl, Na2SO4, NaHCO3, CaCl2, MgCl2·6H2O, and KCl, were bought from Sinopharm Chemical Reagent Co., Ltd. The specific formula can be seen in Table 1. The oil

Table 1. Composition of Simulated Formation Water ingredient mass concentration (mg/L) total dissolved solids (mg/L)

NaCl

Na2SO4

NaHCO3

CaCl2

MgCl2· 6H2O

KCl

8800

400

19500

7.2

100

970

29725.5

with viscosity of 55 mPa·s at 80 °C was composed of dehydrated crude oil and kerosene with a volume ratio of 1:4. The artificial cores with Klinkenberg gas permeability of 0.395 mD and porosity of 4.7% were bought from Hai’an Petroleum Scientific Research Apparatus Co., Ltd. Hai’an, China. 2.2. Methods and Instruments. DPG was first prepared, and mixed with surfactant and brine to form MCSI. The properties of MCSI, including viscosity, interfacial tension, and the ability to improve the wetting performance, were characterized. After matrix− fracture network models were developed in house, the dynamic imbibition of MCSI system in the matrix−fracture network model was studied. 2.2.1. Preparation of Dispersed Particle Gel. The DPG was prepared by high speed shearing method described as follows: first, 0.3 wt % PAM and 0.6 wt % phenolic resin were put into an oven until a bulk gel was formed at 75 °C. Then, water (200 g) and bulk gel (200 g) were added simultaneously to a colloid mill rotating at 3000 rpm and milled for 3 min at 30 °C. A light yellow solution obtained from

Figure 1. Diagrams of (a) actual and (b) physical matrix−fracture network model. 2909

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915

Article

Energy & Fuels

Figure 2. Diagram of schematic dynamic imbibition setup. For a given fracture network model, the length of the total model, L, and the end face sectional area, A, were measured. Confining pressure and axial pressure were adjusted to a certain value. The coefficient, R, was introduced to establish the relationship between the flow rate, Q, and the pressure drop, ΔP.

ΔP = R × Q

Table 2. Main Parameters of Dynamic Imbibition Experiment

(1)

The end face of fracture in the model can be regarded as a rectangle, so the calculation formula which contains the fracture width, w was introduced as follows:

R=

12μd L wh3

(2)

Through the above two equations, the relationship between ΔP and w can be established. Through adjusting the confining pressure, a range of ΔP could be obtained indirectly, so different fracture widths would be successfully established. 2.2.6. Dynamic Imbibition Experiment. The dynamic imbibition experiment was carried out at 80 °C. The equipment used during dynamic imbibition included Isco pump (Model 260D, Teledyne ISCO, America), confining pressure pump, pseudo-tri-axial core holder, piston pump, three accumulators, etc. The actual experimental setup image is shown in Figure S1 in the Supporting Information, and the schematic experimental setup diagram is shown in Figure 2. In this experiment, the oil recovery by dynamic imbibition was studied from five aspects: fluid type, fluid concentration, flow rate, fracture width, and matrix−fracture network model type. The specific impact factors and parameters are shown in Table 2: Taking the flow rate of 0.1 mL/min as an example, the main experimental procedure was as follows: (1) Artificial cylindrical cores were selected and cut into lengths of 2 and 4 cm short sections by using core cutting machine. (2) After each section of core was marked, it was cut horizontally into small core blocks according to the ratio of 1:2 on the crosssectional direction. The length, height, and width of each core block were measured precisely. After drying over high temperature, the dry mass of each piece was weighed. (3) Each small core block was vacuumed and saturated with oil, and then wet mass was weighed. Then the oil content of each small piece was calculated. (4) According to different fracture combination modes, small core blocks were combined into network model. The oil content in each model was calculated, respectively.

(5) Calculate the effective width of the model: After the model was placed in the pseudo-tri-axial core holder, displacement was conducted at the set flow rate of 1 mL/min using oil. According to the functional relation between confining pressure, axial pressure, and fracture width, the expected fracture width was obtained by adjusting axial pressure and confining pressure. (6) Brine flooding: Under the same axial pressure and confining pressure, brine was injected into the model at the flow rate of 0.1 mL/min for 10 pore volumes (PVs). The liquid production and oil fraction were recorded at certain time intervals, and the pressure drop along the model was recorded at the same time. (7) MCSI flooding: With MCSI solution, the procedure was the same as brine flooding. (8) Second water flooding: After the MSCI flooding was finished, the Isco pump was paused and all valves at both ends of the core holder were closed. The confining pressure and axial pressure were still acting on the core holder. The entire experiment setup aged in the oven at 80 °C for 24 h. After aging for 24 h, second water flooding was carried out and all steps were maintained the same. Then, the oil recoveries at different stages were measured. 2910

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915

Article

Energy & Fuels Table 3. Basic Parameters of Dynamic Imbibition model type experiment no. 1 2 3 4 5 6 7 8 9 10 11

length 4 2 2 2 2 2 2 2 2 2 2

cm cm cm cm cm cm cm cm cm cm cm

section

average porosity/%

oil volume/cm3

total oil volume/cm3

fracture width/μm

2 4 4 4 4 4 4 4 4 4 4

18.88 4.98 4.82 4.73 4.41 4.58 3.79 4.46 5.76 6.70 6.23

6.7204 1.8277 1.7644 1.7247 1.6227 1.6465 1.3875 1.5990 2.0388 2.3695 3.3695

8.0204 3.5082 3.4450 3.4052 3.3032 3.3270 3.0680 3.2795 3.7193 4.0500 5.0500

7.7 7.7 7.7 11.6 7.7 7.7 7.7 15.4 7.7 7.7 7.7

Three kinds of fracture widths of 7.7, 11.6, and 15.4 μm were set in the experiment. The basic parameters in the experiments are as shown in Table 3.

3.1.2. Interfacial Tension between Oil and MCSI. The interfacial tensions between oil and 0.1 wt % MCSI and oil and 0.1 wt % surfactant solution were measured with aging time, respectively, as shown in Figure 4.

3. RESULTS AND DISCUSSION 3.1. Fluid Properties. 3.1.1. Viscosity of Mobility Control System with Function of Imbibition. The viscosity of 0.1 wt % THSB surfactant solution, 0.1 wt % DPG solution, and 0.1 wt % MCSI were measured with aging time, respectively. As shown in Figure 3, the viscosities of DPG and MCSI are relative high. With the increase of aging time, the viscosities

Figure 4. Interfacial tensions of two types of fluid with aging time.

From Figure 4, the interfacial tensions for both MCSI and surfactant solution grow over time. The ultralow interface tension maintained by the surfactant is longer, compared with MCSI solution. For the first 8 days, surfactant kept the interface tension to ultralow levels. This is because the surfactant, THSB, is a sulfonate betaine surfactant, which has a chelating effect on the divalent salt ions in brine solution and improves its salt tolerance.42 Under the brine conditions, salt ions could break the hydration shell and reduce the electrostatic repulsion of hydrophilic head groups. More active molecules adsorbed on the oil−water interface and a close interface layer arrangement could be formed. At the same time, due to the existence of salt, some surfactants molecules lost their effectiveness and their adsorption capacity on the oil−water interface were reduced, which made the molecular layer of interface layer relatively sparse.43 As a result, the ability of surfactant to reduce the interfacial tension between oil and surfactant decreased with aging time. However, MCSI solution maintained the interface tension to ultralow levels for 4 days only, then the interfacial tension increased to the 10−2 mN/m level. Surfactant components in MSCI adsorbed on the DPG particle surface by the hydrophobic effect, so the amount of the surfactant molecules in MCSI were reduced.44,45 Therefore, the ability of MCSI to reduce the interfacial tension between oil and water has been reduced.

Figure 3. Viscosity of three types of fluid.

decrease and tend to be stable. The viscosity retention rate is still higher than 70% after 15 days of aging. This indicates that both two systems have good viscosity stability. From the formation mechanism of DPG, bulk gel is a tight network structure formed by the dehydration synthesis between polymer amide group and cross-linking agent methylol. This is mainly related to the formation mechanism of phenolic resin DPG, which means that the bulk gel is a compact network structure formed by dehydration condensation polymer methylol amide and cross-linking agent. The structure can ensure that bulk gel has high viscosity.40 Also, during the preparing process of phenolic resin DPG, bulk gel with tight network structure was only shredded by mechanical shearing, and its viscoelasticity was retained. With time aging, DPG produced a certain degree of aggregation under salt ions, which formed larger particle.41 The nonuniform distribution of DPG reduced the interaction forces between single particle and aggregated particles, thus resulting in the reduction of viscosity. 2911

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915

Article

Energy & Fuels 3.1.3. Wettability Alteration by MCSI. To investigate the ability for fluid to change rock wettability, the surfactant and MCSI solution were used to treat the quartz plates. With the contact angle of oil/water/quartz plate system, water-wet quartz plates were immersed in 0.1 wt % THSB surfactant and 0.1 wt % MCSI for different times. Then, the contact angles of oil droplets were measured carefully, as shown in Figure 5.

Figure 6. Oil recoveries by three types of fluid.

volumetric sweep efficiency. However, MCSI consists of dispersed particle gel and surfactant, which has the advantages of two fluids, thus features of dual function of mobility control and oil discharging by imbibition. So the displacement effect of MCSI is better than each single component, and the mechanisms of dynamic imbibition of various fluids are as shown in Figure 7. Moreover, after aging for 24 h, the oil recovery by second water flooding after MCSI is also higher than that with surfactant and DPG. For surfactant solution, the surfactant molecules were mainly retained in the fractures, and the number of molecules which entered the matrix for imbibition was very small. For DPG solution, DPG particles mainly played a role in blocking the fracture and regulating the mobility, but the main oil had already been discharged during the previous displacement process. For MSCI, the DPG particles could block the fracture in the chemical displacement, which made a large number of surfactant molecules enter into the matrix. After aging for 24 h, the oil in the matrix was stripped to the fracture by imbibition, and the residual oil in fracture and the oil in the matrix could be both displaced through second water flooding. So the oil recovery by second water flooding after MCSI is also higher than that with surfactant and DPG. 3.2.2. Effect of MCSI Concentration. With the 2 cm × 4 section model, at the flow rate of 0.1 mL/min and the fracture width of 7.7 μm, the effects of MCSI with different concentrations (0.06 wt % DPG + 0.1 wt % surfactant, 0.10 wt % DPG + 0.1 wt % surfactant, 0.12 wt % DPG + 0.1 wt % surfactant) on the displacement effect were studied. The relationship between the oil recovery and the MCSI concentration is shown below in Figure 8. From Figure 8, with the increase of MCSI concentration, the oil recovery improves. On the one hand, the increased content of DPG in MCSI solution resulted in more DPG particles, so more displacement fluid molecules were more beneficial to improving the efficiency of the displacement for oil in the fracture. On the other hand, with the increase of the MCSI concentration, more DPG particles blocked the fracture, which made more surfactant molecules enter the core matrix. The oil in the matrix was stripped into the fracture through imbibition and displaced outside. At the same time, these particles played a key role in the mobility control in fractures. The viscosity of the displacement fluid increased and more fracture space was blocked, the mobility was improved and sweep efficiency was enhanced. Therefore, higher DPG content in MCSI solution generates better oil recovery.

Figure 5. Contact angles of oil droplets in different types of fluid after aging.

From Figure 5, both MCSI and surfactant solution could affect the wettability of the quartz plate. The contact angles of oil droplets in both fluids increase with aging. The surfactant components of two systems absorbed on the quartz plate by electrostatic interaction and increased the hydrophilicity of the quartz plate. With the same aging time, the contact angle on surfactant treated quartz plate was higher. This was due to more surfactant molecules contained in the MCSI. With time aging, the amount of surfactant molecules and the adsorption on the quartz plate surface were reduced. In addition, DPG components of MCSI also adsorbed on the water wet quartz plate surface through hydrogen bonding interaction and reduced the adsorption potential on the quartz plate surface. Thus, the adsorption of the surfactant on the quartz plate was reduced. The ability to improve the wettability of quartz plate of THSB surfactant was better than that of MCSI. 3.2. Oil Recovery during MCSI Dynamic Imbibition. 3.2.1. Effect of Fluid Type. With the matrix−fracture network model of the 2 cm × 4 section, at the flow rate of 0.1 mL/min, and the fracture width of 7.7 μm, the oil recoveries by the dynamic imbibition of surfactant, DPG, MSCI solution, and water were studied. The results are shown in Figure 6. From Figure 6, the oil recovery by MCSI solution is the highest among the three chemicals. As for surfactant flooding, on the one hand, surfactant solution first passed through the fracture which was the dominant channel and displaced the oil in the fracture. On the other hand, surfactant molecules absorbed on the matrix surface and the oil in the matrix was stripped by dynamic imbibition. But the mobility control ability of surfactant solution was weak, most of the surfactant molecules passed through the fracture, so the number of surfactant molecules which entered the core matrix to carry out dynamic imbibition was very small. As a result, the increased oil recovery by surfactant flooding is mainly due to the displacement of oil in the fracture. Due to the increased viscosity and larger particle size, the dispersed particle gel mainly developed the ability to improve mobility as increased 2912

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915

Article

Energy & Fuels

Figure 7. Mechanisms of dynamic imbibition of various fluids in tight oil fracture model.

aging for 24 h, the DPG could have aggregated as large particle groups. These would cause blocking in fractures and result in higher water flooding pressure.46 So for all the three different flow rates, the pressure drop of MCSI flooding is only a little higher than that of the second water flooding. The experiment further studied the oil recovery of the MCSI flooding and second water flooding at different flow rates. The results are shown in Figure 10.

Figure 8. Recoveries under different MCSI concentrations.

3.2.3. Effect of Fluid Flow Rate. With the 2 cm × 4 section model, at the fluid concentration of 0.10 wt % DPG + 0.1 wt % surfactant and the fracture width of 7.7 μm, three different flow rates (0.05, 0.10, 0.20 mL/min) were carried out. The injection pressures of MCSI flooding and second water flooding at different flow rates were observed, as shown in Figure 9. Figure 10. Oil recoveries of different flooding agents at various flow rates.

It can be seen that, for the MCSI flooding and second water flooding, the oil recoveries of both systems increase with the reduced flow rate. When two systems flowed through the model at higher flow rates, there was not enough time for them to fully interact with the oil in the fracture. The range of action for the systems was smaller so the displacement efficiency was reduced.47 Besides, it is known that imbibition is the main driving force of oil displacement.48 Especially for MCSI, while the flow rate was higher, the blocking space of DPG particles became smaller. Fewer surfactant molecules entered the matrix and the amount of stripped oil by imbibition was smaller. The mobility control ability of DPG and the imbibition action of surfactant became weaker at higher flow rates. As a result, the oil recoveries of both systems increase with the reducing flow rate. 3.2.4. Effect of Fracture Width. While the 2 cm × 4 section model was used, at the flow rate of 0.1 mL/min and the fluid concentration of 0.10 wt % DPG + 0.1 wt % surfactant, the dynamic imbibition experiment was carried out by adjusting the confining pressure and axial pressure to three corresponding fracture widths: (7.7, 11.6, 15.4 μm). The recovery of MCSI

Figure 9. Pressure drop at three stages with different flow rates.

Figure 9 shows that higher flow rate generates larger pressure drop along the model. From Darcy’s law, the flow rate is proportional to the injection pressure. Besides, for all the three different flow rates, the pressure drop of MCSI flooding is a little higher than that for the second water flooding. This is mainly because that the viscosity of MCSI is much higher than water. It can be known from Darcy’s law that the viscosity is proportional to the injection pressure. After MCSI flooding, there would be some residual of dispersed particle gel. After 2913

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915

Article

Energy & Fuels flooding and second water flooding at different fracture widths is shown in Figure 11.

resistance in fracture increases. Thus, the mobility is decreased, and the oil recovery is higher.

4. CONCLUSIONS (1) With artificial cores, a method to prepare a matrix− fracture network model had been developed. It has the characteristics of controllable fracture length, height, and width. It is also can be replicated and can be used for single factor study. (2) The MCSI system features low viscosity, ultralow oil− water interfacial tension (10−2 mN/m), and strengthening hydrophilicity. These properties would promote the imbibition effect. (3) The MCSI system has dual function of mobility control by DPG and oil discharging through imbibition by surfactant, so the oil recovery during dynamic imbibition in matrix fracture network model is better than that of single surfactant solution and single DPG solution. (4) Within a certain range, the recovery achieved by MCSI flooding and second water flooding is proportional to the MSCI concentration and the fracture network complexity and is inversely proportional to the displacement flow rate. (5) The MCSI system has better mobility control ability in fracture width of 11.6 μm than that in other sizes, and the displacement effect of the second water flooding is also the highest in the matrix fracture network model with the fracture width of 11.6 μm.

Figure 11. Recovery of different driving modes at different fracture widths.

Figure 11 shows that when the fracture width is 11.6 μm, the recoveries of MCSI flooding and second water flooding are both higher than those of 7.7 and 15.4 μm. Therefore, for the dispersed particle gel with an average particle size of 1.3 μm, it matches with the fracture width of the model. Dispersed particle gel has better mobility control ability in the fracture width of 11.6 μm, so the recovery of the second water flooding is the highest in the core model at the fracture width of 11.6 μm. 3.2.5. Effect of the Matrix−Fracture Network Model Type. Two types of matrix−fracture network models (4 cm × 2 section, 2 cm × 4 section) were used to study the effect of model types on oil recovery. The actual diagrams of two types of models are shown in Figure 1a. Dynamic imbibition experiment was carried out at the flow rate of 0.05 mL/min and the fracture width of 7.7 μm. The recoveries of two types of models with MCSI flooding and second water flooding are shown in Figure 12. From Figure 12, while the flow rate and fracture width are certain, the oil recoveries in 2 cm × 4 section network model with MCSI flooding and second water flooding are higher than those with 4 cm × 2 section network model, respectively. When the fracture network becomes more complex, the flowing

■

ASSOCIATED CONTENT

S Supporting Information *

The Supporting Information is available free of charge on the ACS Publications website at DOI: 10.1021/acs.energyfuels.7b03283. Image of the actual experimental setup (PDF)

■

AUTHOR INFORMATION

Corresponding Author

*Phone: 86-532-86981183. Fax: 86-532-86981161. E-mail: [email protected] (C.D.). ORCID

Mingwei Zhao: 0000-0002-9671-8206 Caili Dai: 0000-0002-7477-8865 Yongpeng Sun: 0000-0003-3836-5083 Qing You: 0000-0002-0959-9502 Guang Zhao: 0000-0003-1955-7936 Notes

The authors declare no competing financial interest.

■

ACKNOWLEDGMENTS The work was supported by the National Science Fund for Distinguished Young Scholars (No. 51425406), the Chang Jiang Scholars Program (No. T2014152), the National Key Basic Research Program (No. 2015CB250904), the Climb Taishan Scholar Program in Shandong Province (No.tspd20161004), the Outstanding Young Scientist Award o f S h a n d o n g Na t u ra l S c i e n ce F o u n d a t i o n ( No . ZR2016EEB35), and the Fundamental Research Funds for the Central Universities (14CX02184A, 16CX02056A).

Figure 12. Recoveries of two types of matrix−fracture network models. 2914

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915

Article

Energy & Fuels

■

(26) Zou, B.; Mccool, C. S.; Green, D. W. Precipitation of chromium from chromium acetate solution. SPE Int. Symp. Oilfield Chem. 1999, 50742. (27) Lei, W. Design and performance evaluation of thermalresistance and salt-tolerance MSCI phase combination flooding system. Thirtieth Annual Meeting of the Chinese Chemical Society− Eleventh branch: Applied Chemistry[C] Chinese Chemical Meeting; 2016; p 1. (28) Cao, X. J. Petr. (Petr. Process.) 2013, 29 (1), 115−121. (29) Dai, C.; Zhao, G.; You, Q. The investigation of a new moderate water shutoff agent: Cationic polymer and anionic polymer. J. Appl. Polym. Sci. 2014, 131, 631−644. (30) Xue, Y. Study on fracture model of low permeability reservoir in Xinli Oilfield. Fault Block Oil Gas Field 2010, No. 04, 462−465. (31) Li, A.; Fan, T.; Zhao, L. Experimental study on spontaneous imbibition in fractured reservoirs with low permeability. Petr. Geol. Recov. Efficiency 2011, No. 05, 67−69, 77, 115−116. (32) Liang, Q. Study on productivity of fractured horizontal well in low permeability reservoir. Changjiang University, 2015; p 1−10. (33) Yang, Z.; Zhu, W.; Chen, Q. Imbibition mechanism of low permeability fractured sandstone reservoir and its mathematical model. J. Jianghan Petr. Inst. 2001, No. S1, 25−27+6. (34) Chen, K. Study on preparation, performance evaluation and application of micro gel. China University of Petroleum (East China), 2007; p 129. (35) You, Q.; Dai, C.; Zayne, Lu Research on a new profile control agent: Dispersed particle gel. SPE Enhanced Oil Recov. Conf. 2011, 143514. (36) Jiang, P.; Li, N.; Ge, J.; et al. Efficiency of a sulfobetaine-ypre surfactant on lowering IFT at crude oil-formation water interface. Colloids Surf., A 2014, 443, 141−148. (37) Zhang, S.; Liu, J.; Deng, Y. The uncertainty of surface contact angle in the reservoir rock. J. Miner. Petr. 2001, 21 (1), 48−51. (38) Wang, X.; Guo, Y.; Zhang, J. Comparsion of methanol, gasoline and methanol-gasoline as motor fuel. Chem. Ind. Times 2008, 30 (1), 8−12. (39) Liu, S.; Ma, Z.; Wang, P. Technical performance of methanol gasoline fuel for vehicle. J. Chang'an Univ. (Nat. Sci. Ed.) 2007, 30 (7), 31−35. (40) Zhao, G.; Dai, C.; Chen, A.; et al. Experimental study and application of gels formed by nonionic polyacrylamide and phenolic resin for in-depth profile control. J. Pet. Sci. Eng. 2015, 135, 552−560. (41) Zhao, G.; You, Q.; Gu, C. Preparation mechanism of multiscale dispersed particle gel. Acta Petr. Sin. 2017, 38 (7), 821−829. (42) Zhang, W.; Yu, T. Research progress of betaine surfactants used in EOR. Chem. Eng. 2013, 27 (01), 42−45. (43) Zhao, H.; Gong, H.; Xu, G. Investigation of Salts Tolerance of Anionic Surfactants in Aqueous Solutions. Oilfield Chem. 2010, 27 (01), 112−118. (44) Ma, T.; Tang, D.; Zhang, G. Adsorption behavior of surfactant in oil water interface. Appl. Chem. Ind. 2007, 10, 1017−1020. (45) Zhao, G.; Dai, C.; Chen, A.; et al. Experimental study and application of gels formed by nonionic polyacrylamide and phenolic resin for in-depth profile control. J. Pet. Sci. Eng. 2015, 135, 552−560. (46) Zhao, G.; You, Q.; Tao, J.; et al. Preparation and application of a novel phenolic resin dispersed particle gel for in-depth profile control in low permeability reservoirs. J. Pet. Sci. Eng. 2018, 161, 703. (47) Liu, H. Hypotensive and annotation technology for composite active system. China Petr. Chem. Stand. Qual. 2013, 33 (12), 76. (48) Li, Z.; Wang, P.; Lu, T. Experimental study on enhanced foamy oil recovery after solution gas drive by waterflooding. J. China Univ. Petr. 2014, 38 (03), 87−92.

REFERENCES

(1) Maugeri, L. The shale oil boom: a US phenomenon; Harvard Kennedy School; 2013. (2) EIA, U. S. Technically recoverable shale oil and shale gas resources: an assessment of 137 shale formations in 41 countries outside the United States; US Department of Energy/EIA: Washington (DC); 2013. (3) Cao, Z.; Liu, G.; Liu, Z. The present situation and prospect of the research on tight oil geology. Nat. Gas Geosci. 2014, 25 (10), 1499− 1508. (4) Zhao, H.; Ning, Z.; Wang, Q.; et al. Petrophysical characterization of tight oil reservoirs using pressure-controlled porosimetry combined with rate-controlled porosimetry. Fuel 2015, 154, 233−242. (5) Clarkson, C. R.; Jensen, J. L.; Blasingame, T. A. Reservoir engineering for unconventional gas reservoirs: what do we have to consider. SPE North Am. Unconventional Gas Conf. Exhib. 2011, 145080. (6) Lai, F.; Li, Z.; Wei, Q.; et al. Experimental investigation of spontaneous imbibition in a tight reservoir with nuclear magnetic resonance testing. Energy Fuels 2016, 30, 8932−8940. (7) Liu, Y.; Lu, Q.; Wang, J. Study on enhanced oil recovery by two element compound flooding in Jinzhou 9−3 Oilfield. Petr. Geol. Recov. Efficiency 2009, 6 (4), 68−70. (8) Kathel, P.; Mohanty, K. K. Wettability alteration in a tight oil reservoir. Energy Fuels 2013, 27, 6460−6468. (9) Zhao, F. Oilfield chemistry; China University of Petroleum press, 2010; pp 129−158. (10) Zhao, F.; Dai, C.; Wang, Y. Connotation and key technology of water shutoff in oil well. Acta Petr. Sin. 2006, 27 (5), 71−78. (11) Yao, J.; Deng, X.; Zhao, Y. Characteristics of tight oil in Yanchang Formation of Ordos Basin. Petr. Exp. Dev. 2013, 40 (2), 150−158. (12) Cai, J.; Yu, B.; Zou, M.; et al. Fractal characterization of spontaneous co-current imbibition in porous media. Energy Fuels 2010, 24, 1860−1867. (13) Schechter, D. S.; Zhou, D.; Orr, F. M. Low IFT drainage and imbibitions[J]. J. Pet. Sci. Eng. 1994, 11 (4), 283−300. (14) Yao, T.; Li, J.; Wang, J. Imbibition mechanism and favorable conditions of fractured low permeability reservoir. J. Jilin Univ. (Eng. Sci. Ed.) 2009, 39 (4), 937−400. (15) Prateek, K.; Mohanty, K. K. EOR in tight oil reservoirs through wettability alteration. SPE Annu. Techn. Conf. Exhib. 2013, 166281. (16) Chen, P.; Mohanty, K. K. Surfactant-enhanced oil recovery from fracture oil-wet carbonates: effects of low IFT and wettability alteration. SPE Int. Symp. Oilfield Chem. 2015, 173797. (17) Adibhatla, B.; Mohanty, K. K. Oil recovery from fractured carbonates by surfactant-aided gravity drainage: laboratory experiments and mechanistic simulations. SPE Res. Eval. Eng. 2008, 11, 119. (18) Saunders, B. R.; Vincent, B. Microgel particles as model colloids: theory, properties and applications. Adv. Colloid Interface Sci. 1999, 80 (2), 1−25. (19) Pelton, R. Temperature-sensitive aqueous microgels. Adv. Colloid Interface Sci. 2000, 85 (1), 1−33. (20) Chauveteau, G.; Tabary, R.; Renard, M.; et al. Controlling Insitu gelation of polyacrylamide by zirconium for water shutoff. SPE Int. Symp. Oilfield Chem. 1999, 50752. (21) Qing, Y.; Yu, H.; Wang, Y. Research progress of deep profile control technology in domestic oil field. Fault Block Oil Gas Field 2009, 16 (4), 68−71. (22) Zhao, F.; Wang, F.; Yang, N. Study and application of plugging agent for the whole water shutoff in the south block of the west block of the east oil field. J. Petr. 1991, 12 (1), 39−47. (23) Yin, Y.; Zhang, G. Review of chemical water shutoff and profile control agent. Petr. Geol. Recovery Efficiency 2003, 10 (6), 64−66. (24) Broseta, D.; Marquer, O.; Blin, N.; et al. Rheological screening of morecular weight polyacrylamide/chronium III acetate water shutoff gels. SPE/DOE Improved Oil Recov. Symp. 2000, 59319. (25) Moffitt, P. D.; Moradi-Araghi, A.; Ahmed, I.; et al. Development and field testing of a new low toxicity polymer crosslinking system. Permian Basin Oil Gas Recov. Conf. 1996, 283−289. 2915

DOI: 10.1021/acs.energyfuels.7b03283 Energy Fuels 2018, 32, 2908−2915