Wettability Alteration Study of Supercritical CO2 Fracturing Fluid on

Nov 7, 2017 - On the basis of the results of spontaneous imbibition, strong lipophilicity cores corresponded to lower oil recovery, which illustrated ...
0 downloads 9 Views 2MB Size
Download PDF
Article Cite This: Energy Fuels XXXX, XXX, XXX-XXX

pubs.acs.org/EF

Wettability Alteration Study of Supercritical CO2 Fracturing Fluid on Low Permeability Oil Reservoir Xin Sun,† Caili Dai,*,† Yongpeng Sun,*,† Mingyong Du,‡ Tao Wang,† Chenwei Zou,† and Jiayuan He§ †

State Key Laboratory of Heavy Oil Processing, School of Petroleum Engineering, China University of Petroleum (East China), Qingdao, Shandong 266580, People’s Republic of China ‡ School of Mechanical and Chemical Engineering, The University of Western Australia, Craley 6009, WA, Australia § Petroleum Exploration & Production Research Institute, SINOPEC, Beijing 100083, People’s Republic of China ABSTRACT: Hydraulic fracturing has become an important stimulation technique for low/ultralow permeability reservoirs. Supercritical CO2 (SC-CO2), as a no water phase material of fracturing fluid, receives wide attention. Current researches on SCCO2 fracturing fluid has mainly focused on its viscous properties and superiorities. However, little attention has been devoted to the interaction between SC-CO2 fracturing fluid and the oil reservoir during the fracturing process. Besides, in a low permeability reservoir, the wettability determines the oil recovery by imbibition, which is a main way to explore oil for a matrix. Therefore, it is crucial to study the wettability alteration on a low permeability oil reservoir introduced by SC-CO2 fracturing fluid. In this study, a contact angle goniometer was introduced to characterize the wettability alteration on low permeability cores by SC-CO2 fracturing fluid. Meanwhile, nuclear magnetic resonance T2 spectra, a scanning electron microscope, and a energy dispersive spectrometer were used to explain the mechanisms of wettability alteration and the adsorption of fracturing fluid was analyzed. In addition, spontaneous imbibition tests were conducted to definite the impact of wettability alteration on oil production. The results showed that the thickener in SC-CO2 fracturing fluid, fluid filter loss, and reservoir permeability were all responsible for wettability alteration on the core surface. With the increasing thickener contents and filter loss of fracturing fluid, cores turned to be intermediate and slightly water-wet from initial strongly water-wet, which was unfavorable for oil production.Comparatively low permeability cores which consist of more micro-small pores were more likely to make treated cores oleophilic, as well. Thickener adsorption was confirmed to be the main mechanism on wettability alteration by SC-CO2 fracturing fluid, which resulted in different pore surfaces, and thus a more oleophilic cores surface. On the basis of the results of spontaneous imbibition, strong lipophilicity cores corresponded to lower oil recovery, which illustrated that wettability alteration caused by SC-CO2 fracturing fluid was not favored for oil flow.

1. INTRODUCTION

(3) There is a small quantity of residual in the formation after fracturing, so the damage to formation permeability is little. (4) SC-CO2 is a wonderful energized material; it can flow back quickly. (5) Because of the greater adsorption capacity of CO2 than CH4 in shale, it can replace the methane and increase gas production and recovery when it was used to fracture the shale well. (6) CO2 can dissolve in oil to reduce oil viscosity; this is favorable for oil production. (7) The use of CO2 fits global environmental policies and has benefits in terms of controlling a greenhouse gas. However, the low viscosity of SC-CO2 is the main challenge of SC-CO2 fracturing for large scale applications at present. The viscosity of SC-CO2 as a fracturing fluid is (0.03−0.10) mPa·s at reservoir conditions. Low viscosity leads to poor proppant carrying capacity and affects the opening of fractures, and thus production channels. Therefore, some additives in the SC-CO2 fracturing fluid system are required to increase the viscosity, such as thickeners and cosolvents.

Unconventional oil and gas reservoirs which contain ultralow permeability are becoming more and more important to energy supplies across the world. Low permeability formations contain massive nano- to microscale pore networks and complex minerals.1 Their porosities are typically less than 20%, and permeabilities are in the range of nano-Darcy to 50 milliDarcy.2 Therefore, these kinds of reservoirs are usually hydraulic fractured to improve the poor permeability and pore connectivity. For fracturing fluid, water based hydraulic fracturing fluids are the most commonly used materials, such as liner or crosslinked hydroxypropyl gum, guar gum, and polymer.3 However, during the flowback process, due to factors such as incomplete gel breaking, high residue retention, the reservoir is very easy to be damaged, especially for a low permeability matrix. On that account, SC-CO2, as a rising waterless fracturing material, has received wide attention for its unique advantages:4 (1) Strong mobility makes CO2 easy to enter nano- to micrometer pores, microchannels, and connect fracture networks. (2) Because of the waterless fluid system, water-sensitive damage can be avoided. © XXXX American Chemical Society

Received: August 28, 2017 Revised: October 26, 2017

A

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels Table 1. Viscosity of SC-CO2 Fracturing Fluid (42 °C, 20 MPa) sample no.

thickener concentration (wt %)

cosolvent concentration (wt %)

viscosity of fracturing fluid (mPa·s)

1 2 3 4 5 6 7 8 9 10 11 12

0.5 0.5 0.5 1.0 1.0 1.0 3.0 3.0 3.0 5.0 5.0 5.0

10 15 20 10 15 20 10 15 20 10 15 20

0.75 0.65 0.50 1.10 0.99 0.91 1.31 1.17 1.04 1.43 1.31 1.05

process of fracturing, and very little research had been conducted on the interaction between fracturing fluid and reservoir matrix (e.g., wettability and permeability alteration). Furthermore, based on plenty of micropores and channels in a low permeability reservoir, imbibition is considered to be a main way to explore oil from the matrix, and the oil recovery from imbibition depends on the wettability of the reservoir matrix. The wettability of the reservoir matrix also contributes to the oil recovery through imbibition. Therefore, it is crucial to study the wettability alteration on a low permeability oil reservoir introduced by supercritical CO2 fracturing fluid. In this research, the wettability alteration laws and mechanism of SC-CO2 fracturing fluid on a low permeability oil reservoir was studied. In this research, different factors and the mechanism for wettability alteration were clarified, which can provide new sight and data support for SC-CO2 fracturing construction. The main objective of this work was to study the wettability change under different conditions such as the thickener in fracturing fluid, fracturing fluid filter loss, and formation permeability. A secondary objective was to determine how the wettability change was generated. In addition, spontaneous imbibition tests were conducted to investigate the internal wettability of cores and the impact of wettability alteration on oil production was defined.

Middleton et al. proposed a nonaqueous method for fracturing shale using SC-CO2 as a fracturing fluid.5 This proposal had received great attention and extensive research all over the world.6−8 He et al. summarized the advantages of CO2 and forecasted the application status and development trend of CO2 fracturing.9 They pointed out that CO2 has strong mobility to connect nano- to microfracture networks and it can dissolve in oil to reduce oil viscosity after fracturing. Ishida et al. conducted an experimental study with SC-CO2 and liquid CO2 to fracturing granite, and compared with water based fracturing. Their study indicated that the breakdown pressures needed for SC-CO2 and liquid CO2 fracturing were smaller than those needed for water based hydraulic fracturing.10,11 Although CO2 fracturing fluid has been proved to be a low damage and environmentally friendly fracturing fluid, there are some disadvantages, which would impact the matrix of the oil reservoir inevitably, such as permeability reduction, wettability alteration, etc. Meanwhile, it is worth nothing that the presence of nano- to micropores, and microfractures in the unconventional matrix causes high capillary pressures,3 which is closely related to unconventional oil and gas production. Therefore, wettability alteration after fracturing is a very basic and essential content to evaluate the postfrac properties. Researchers have made great efforts on the research of wettability alteration in unconventional reservoirs after fracturing. Li et al. invented a new non-guar gum polymer fracturing fluid, and its wettability impact on a sandstone reservoir was evaluated. They found that this fracturing fluid system can make the rock more hydrophilic which is beneficial for oil production.12 Chen et al. studied the wettability alteration caused by cationic surfactant base fracturing fluids on a sandstone reservoir. They pointed out that, after fracturing fluid injection, the viscoelastic surfactant (VES) system absorbed on the pore surface of formation, which reversed the wettability and the size of the pore throat performed to be decreased.13 Fang et al. made a similar conclusion with a novel viscoelastic anionic surfactant (VAS) fracturing fluid.14 Bai et al. took a wettability test on Fayetteville shale. The results revealed that the shale surface is originally intermediate-wet and most of the additives used in hydraulic fracturing fluids can alter shale gas surfaces toward water-wet conditions.15 In addition, Zhou et al. evaluated the damage of clean fracturing fluid for coal petrography. It showed that fracturing fluid filtrate could adsorb on the coal surface to alter the wettability and reduce the desorption capacity of Coalbed Methane (CBM).16 However, for SC-CO2 fracturing fluids, most of the research focused on their role for fracture width generation in the

2. EXPERIMENTAL SECTION 2.1. Materials. 2.1.1. Fracturing Fluid. A novel SC-CO2 fracturing fluid was used in this study, which consisted of CO2, thickener, and cosolvent. Silicohydride was used as thickener to increase the viscosity of fracturing fluid, which meant better shear resistance, proppant carrying capacity, and less filtration. Methylbenzene was used as cosolvent to improve the dissolving capacity between SC-CO2 and thickener, which meant lower miscible pressure and easier preparation for fracturing fluid. A high temperature and high pressure rheometer was employed to measure the viscosity of the fracturing fluid with various concentrations of thickener and cosolvent at 42 °C, which is shown in Table 1. 2.1.2. Oil. Crude oil from Jimsar block, Zhundong Oilfield, was employed in this study. The crude oil was centrifuged and filtered through a 5 μm Millipore filter to remove water, solids, and other deposits prior to use, respectively.17 According to the actual viscosity of underground oil, the experimental oil with a density of 0.8047 g/ cm3 and a viscosity of 5.17 mPa·s at 20 °C was prepared by mixing crude oil with aviation kerosene in definite proportions. The mixed oil was used in this study. 2.1.3. Brines. The synthetic brine solutions were prepared with deionized water and salts (AR, Shanghai Aladdin Biochemical Technologies Inc., Shanghai, China). The brine had total dissolved solids of 53219.57 mg/L. The major ionic composition is presented in B

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels Table 2.18,19 This brine was filtrated using a 0.1 μm syringe filter before any measurements.

(1) Cores were cut into design length, cleaned, dried, and saturated with oil with the vacuum and pressurizing method. (2) Measure the contact angle with a brine drop on the oil saturated core with a goniometer.20,21 (3) Put the core into the core holder, and inject oil to saturate the inlet tubing, to avoid the air contamination during SC-CO2 fracturing fluid treatment. The oil flow rate was kept at 0.5 mL/ min until flow rate and pressure become steady and then keep injection for more than 60 min. (4) The SC-CO2 fracturing fluid was used to treat the core. Prepare the SC-CO2 fracturing fluid and push it into the core as treatment. With the control of BPR, the flooding was maintained for 30 min, at a temperature of 42 °C. After this, both valves on the two sides of the core holder were closed on for 120 min. The aging would help the diffusion of fracturing fluid in the porous media. (5) Take the sample out of the core holder, measure the contact angle again, and compare with the initial contact angle before treatment. 2.2.2. Wettability Measurement. Wettability was evaluated by considering the contact angle on the core surface before and after the SC-CO2 fracturing fluid treatment. The HARKE-SPCA contact angle goniometer from the Beijing Hakko test has been employed to measure the contact angle between water drop, air, and rock surface.1,22,23 Nine low permeability cores were employed in this part. Before the measurement, the extra free oil on the surface of core samples was removed by Kimwipes by Kimberly-Clark. When the sample was placed on the stage and the top surface was leveled, a certain volume of brine drop was placed on the top surface. The angle between water, air, and rock surface was calculated with the built-in software. 2.2.3. Fluid Adsorption in Porous Media with NMR. Nuclear Magnetic Resonance (NMR) technology was able to identify the signals of the hydrogen atom with T2 relaxation, which would be able to reflect pore structure and/or recognize the existence of signal matter, such as normal oil and water. An NMR system (Micro MR 12025 V, Niumag Analytical Instrument Inc., Suzhou, China) was used to measure T2 spectra in core samples at ambient condition. A Carr− Purcell−Meiboom−Gill pulse sequence was used to measure the T2 spectra.24,25 The parameters used in this test are listed as follows: spectrometer frequency (SF) was 11 MHz, frequency offset 1 (O1) was 793442.7 Hz, frequency width of the receiver was 200 kHz, number of scans was 128, waiting time between two scans was 3000 ms, and echo interval was 0.10 ms. The optimal settings of echo time and number of echoes were set with reference to the work of Ronczka and Müller-Petke.26 Echo time and the number of echoes were varied to minimize the energy input into the sample without compromising the ability to obtain the complete spectrum of relaxation times. The acquired data sets were then inverted by software with an algorithm which used an “inverse Laplace transform” (ILT) to calculate the T2 spectra.

Table 2. Major Ionic Composition of Formation Brine brine composition (mg/L) Na+

Ca2+

Mg2+

Cl−

salinity (mg/L)

14312.29

5803.08

180.46

32923.74

53219.57

2.1.4. Cores. Strongly water-wet low permeability cores were employed in the experiments. All the core samples were well cemented sandstone, with 2.5 cm in diameter and 3 or 5 cm in length, with a porosity range of 6.78−18.20% and a permeability range of (0.54− 25.95) × 10−3 μm2, mostly around 1.0 × 10−3 μm2. The basic data of the core samples are listed in Table 3.

Table 3. Basic Parameters of Core Samples sample no.

length (mm)

diameter (mm)

pore volume (cm3)

porosity (%)

permeability (×10−3 μm 2)

HR-1 HR-2 HR-3 ZR-1 ZR-2 ZR-3 SR-1 SR-2 SR-3 MR-1 MR-2 MR-3 MR-4 ER-1 ER-2 ER-3 ER-4

49.03 50.39 50.85 49.83 51.02 50.58 49.28 51.13 51.15 31.46 31.50 31.63 31.50 31.62 31.69 31.96 31.55

25.36 25.25 25.23 25.47 25.20 25.42 25.17 25.26 25.28 25.20 24.89 25.03 25.12 25.10 24.99 25.12 25.11

1.84 1.98 1.72 4.00 4.53 4.58 4.07 4.66 4.62 2.39 2.28 2.43 2.31 1.83 2.03 2.15 2.10

7.42 7.84 6.78 15.76 17.81 17.84 16.60 18.20 17.99 15.233 14.855 15.627 14.834 11.73 13.05 13.57 13.45

1.22 1.37 1.18 1.56 1.55 1.45 1.85 17.71 25.95 0.70 0.75 0.54 0.59 0.94 1.23 1.17 1.01

2.2. Instruments and Methods. 2.2.1. SC-CO2 Fracturing Fluid Treatment on Core Samples. All the 15 core samples were treated by a SC-CO2 fracturing fluid treatment system. The system included a CO2 phase equilibrium system and a core flooding setup, as shown in Figure 1. The CO2 phase equilibrium system included a CO2 tank, a CO2 accumulator, a gas booster pump, an oil bath, a circulating pump, a reactor, and a hand pump. The maximum confining pressure was 40 MPa, and a maximum working temperature was 120 °C. The core flooding system consisted of a constant temperature oven, a core holder, a back-pressure regulator (BPR), an exhaust treatment device, two hand pumps, and several pressure sensors. The specific steps were as follows:

Figure 1. SC-CO2 fracturing fluid treatment system: (a) CO2 tank, (b) gas booster pump, (c) CO2 accumulator, (d) oil bath, (e) SC-CO2 fracturing fluid reactor, (f) hand pump, (g) core holder, (h) oven, (i) back-pressure regulator, (j) exhaust treatment device. C

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels Four core samples with very close properties were screened and employed in this experiment. The detailed procedure is listed as follows: (1) Cores were treated with SC-CO2 fracturing fluid with different concentrations of thickener for 120 min, respectively. (2) Cores were dried in an oven at 120 °C for 12 h to confirm CO2 and cosolvent had completely disappeared. (3) Put the core in the special cell to measure the T2 signal within the sample. The adsorption of thickener could be monitored and the corresponding adsorption pores could be inferred from the T2 spectra graph.27,28 It should be noted that the T2 spectra test with NMR will not do harm on the core samples or have an impact on the fluid distribution in the porous media. Therefore, core samples were continued to make spontaneous imbibition test after NMR T2 spectra test. 2.2.4. Microscopic Morphology with SEM-EDS. For the core samples treated with SC-CO2 fracturing fluid, the adsorption and morphology of the thickener in the porous media in microscale were examined with an ultra-high-resolution Scanning Electron Microscope (S-4800, Hitachi Limited Corporation, Japan). The photographs were taken to show the direct changes in sample surfaces by thickener adsorption. These data can also be used as secondary evidence to explain the adsorption amount of thickener. Multiple points were observed and statistical characters were selected as general results.29,30 Four core samples with very close properties were employed in the SEM-EDS test. Among the samples, one was untreated and the other was treated with SC-CO2 fracturing fluid of different concentrations of thickener. After the treatment, core samples were chipped off and trimmed to an appropriate size to adapt to the requirement of the SEM instrument.31 All treated and untreated samples were then dried and coated with a gold coating before SEM-EDS examination. 2.2.5. Spontaneous Imbibition. As an important pattern to displace oil from reservoirs arising from capillary force, the static spontaneous imbibition test was identified as an appropriate way to check the internal wettability of the core samples.32−34 Amott imbibition cells were used to conduct the imbibition. The detailed procedures were as follows: (1) 4 core samples with very close properties were treated with SCCO2 fracturing fluid. Then, these cores were dried in an oven at 120 °C for 12 h, in order to evaporate the cosolvent thoroughly. (2) After cooled to room temperature, the mass of dry cores was examined. Then, cores were vacuumed for 12 h and saturated with oil under the pressure of 15 MPa. (3) Prepare the imbibition brine according to its composition which is listed in section 2.1. (4) After the saturation, all of the brine and cores which were immersed in experimental oil, which was placed in a water bath at 55 °C for 2 h, to avoid the influence of temperature change. Then, the mass of cores was examined again. The volume of oil saturated in cores could be calculated with the oil density at 55 °C. (5) Cores were immersed in the imbibition cell filled with brine,35,36 as shown in Figure 2. These cells were placed in a thermostat water bath at 55 °C for 2 h before the placement of core samples. During imbibition, the volume of oil expelled from the cores (expressed as a percentage of original oil in place (OOIP)) could be read from the scale on the top of the cell and was recorded versus time.

Figure 2. Imbibition cell.

fluid with 10 wt % cosolvent and different concentrations of thickener, respectively. The initial wettability and the wettability after the treatment including initial contact angles, contact angles after treatment, and the variation of contact angle are shown in Figures 3 and 4. As mentioned in section 2.1, cores are strongly water-wet (contact angle is 0°) before oil saturation. When they were saturated with oil, the core surface became more like intermediate wet (contact angle was nearly 90°). As the Figures 3 and 4 show, the initial contact angles of HR-1/2/3 are 83.84°/85.41°/83.11°, respectively. That is to say, the initial core surface is more like intermediate wet because of oil saturation. However, after the treatment of fracturing fluid, the surface dramatically changes to water-wet. As Figure 4 shows, the contact angles are all decreased after treating with SC-CO2 fracturing fluid. Specifically, the contact angle variation of the 1 wt % thickener achieves 83.84° (completely water-wet), where 2 wt % achieves 60.74° and 45.35° for 3 wt %. Therefore, the concentration of thickener in the fracturing fluid has an apparent impact on the wettability of the core surface. In other words, a lower concentration of thickener can achieve a stronger water-wet surface. This is because, when the fracturing fluid was injected into core samples, the effective displacement occurred and most oil was flooded out of core samples. Therefore, the core samples are recovered to water-wet. In contrast, a higher concentration of thickener was more likely to have more adsorption on the core surface. In the meantime, it should be noted that the thickener is an oil-wet liquid. This means the absorbed layer on the core surface is more likely to change the surface to be oil-wet. This is the reason the higher

3. RESULTS AND DISCUSSION 3.1. Core Surface Wettability Impacted by SC-CO2 Fracturing Fluid. 3.1.1. Impact of Thickener Concentration. To simulate the real fracturing process, contact angle was measured on the same surface as the fracturing fluid injection surface. Three oil saturated cores (HR-1, HR-2, and HR-3) were treated with 20 pore volume (PV) of SC-CO2 fracturing D

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

Figure 3. Photo of contact angle on cores surface treated with different concentrations of thickener.

Figure 4. Contact angle on cores surface treated with different concentrations of thickener.

Figure 6. Contact angle on cores surface treated with different filter loss.

concentration of thickener causes a less water-wet core surface, which is unfavorable for oil production. 3.1.2. Impact of Fracturing Fluid Filter Loss. To simulate the different fracturing fluid filter loss through the fracture face

to reservoir matrix, we took the fracturing fluid flooding experiments in this test. Three oil saturated cores (ZR-1, ZR-2, and ZR-3) with a permeability of (1.45−1.56) × 10−3 μm 2 were treated with different PVs of SC-CO2 fracturing fluid with

Figure 5. Photo of contact angle on cores surface treated with different filter loss. E

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

Figure 7. Photo of contact angle on cores surface with different permeabilities.

Figure 10. NMR T2 spectra area versus core wettability.

Figure 8. Contact angle on cores surface treated with different permeability cores (1 mD = 1 × 10−3 μm2).

wettability. The contact angle decreases 82.08° (completely water-wet) with 10 PV filtration, 61.76° with 20 PV filtration, and 15.21° for 30 PV filtration, respectively. When the fracturing fluid was injected into the core samples, less filtrated volume caused less adsorption of oil-wet thickener on the mineral of the core sample. This means less filtrated volume can achieve a greater wettability change to the rock than large filtrated volume of fracturing fluid, which is good for oil production. 3.1.3. Impact of Core Permeability. Three cores of different permeabilities (SR-1, SR-2, and SR-3) were employed in this experiment. The 20 PV fracturing fluid including 1 wt % thickener and 10 wt % cosolvent was injected into each core, respectively. The contact angle data are drawn in Figures 7 and 8. As shown in Figure 7, the initial permeability of the core sample has a significant impact on wettability after the treatment of SC-CO2 fracturing fluid. According to the data shown in Figure 8, after the treatment, the core with an initial permeability of 1.85 × 10−3 μm2 shows 11.25° contact angle decreasing, and the cores with an initial permeability of 17.72 × 10−3 μm2 and 25.95 × 10−3 μm2 show 66.84° and 83.99° decreasing in contact angle, respectively. According to Table 3, the porosity of 3 cores in this experiment is similar (16.60%, 18.20%, and 17.99%). Therefore, the reasons for the difference

Figure 9. T2 spectra of thickener in treated core sample by NMR.

1 wt % thickener and 10 wt % cosolvent, respectively. The detailed data are shown in Figures 5 and 6. From Figures 5 and 6, it can be seen that the PV of fracturing fluid filtration has an apparent impact on the wettability of core surfaces. Less filtrated volume achieves a dramatic change of F

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

Figure 11. SEM images of core surfaces: (A) ER-1 treated with 0% thickener, (B) ER-2 treated with 1% thickener, (C) ER-3 treated with 2% thickener, (D) ER-4 treated with 3% thickener.

thickener contents, adsorption amount is bigger and bigger, which can form a good correspondence with experimental results in section 3.1.1. 3.3. Adsorption Morphology of SC-CO2 Fracturing Fluid on Sample Surface with SEM-EDS. To figure out the adsorption characters and distribution of thickener, a group of dried cores (ER-1, ER-2, ER-3, ER-4) were treated with SCCO2 fracturing fluid with different concentrations of thickener first. Then, they were examined by scanning electron microscope (SEM) and energy dispersive spectrometer (EDS), as shown in Figures 11 and 12. From Figure 11, the absorption of thickener on the minerals of the core sample is increasing from zero adsorption (A) to scattered spots with a few stacks (B) to fully spreading over the mineral with a few empty areas (C) to fully spreading over the mineral with many liquid drops (D). Figure 11A shows that the core sample is almost consisted of irregular quartz grains with sharp edges, and almost nothing covers the grain surface with 0% concentration thickener. In addition, Figure 11A reveals the reason that untreated cores and 0% thickener treated cores are strongly water-wet. In Figure 11B, where the sample was treated with 1% concentration of thickener, thickener spots are majorly scattered on the core surface with only a few were stacked together. Then, the wettability of the core was expected to be slightly less water-wet than the untreated one, where this was a physical evidence in microscale for the observation in macroscale contact angle measurement. Figure 11C illustrates that the thickener spots are much more densely absorbed on the mineral surface, which is almost forming a coating there. Therefore, the sample surface wettability was suspected to be more oil-wet. From Figure 11D, it can be seen that the thickener is fully absorbed on the core surface and forms a uniform adsorption layer with many liquid drops, which would make the wettability further turn to oil-wet.

in permeability are pore connectivity, pore tortuosity, and pore radius. Lower permeability cores may have more complicated pore connectivity and pore tortuosity. This makes the core crossing of SC-CO2 fracturing fluid more complex. Meanwhile, the thickener is accordingly more likely to adsorb on pore surfaces. Similarly, lower permeability usually corresponds to smaller pore radius. Therefore, under the same porosity condition, cores with a smaller pore radius have larger pore surface, which means a larger area to take the adsorption. For the above reasons, low permeability cores have changed less water-wet than high permeability. This phenomenon leads to an inferior production increasement for lower permeability reservoirs after fracturing operation. 3.2. Adsorption of SC-CO2 Fracturing Fluid in Porous Media by NMR. To determine whether the wettability alteration is mainly caused by thickener adsorption, a group of dried cores (MR-1, MR-2, MR-3, MR-4) with a permeability of (0.54−0.75) × 10−3 μm 2 were treated with fracturing fluid with different concentrations of thickener first. Then, the existence of thickener in the pores of samples was measured by NMR. Their T2 spectra and spectra area are shown in Figures 9 and 10. By analyzing Figures 9 and 10, three conclusions can be obtained as follows. First, it has no signal in the NMR apparatus, if cores are not saturated by oil. However, when they are adsorbed by silicohydride thickener, they will have a strong signal in NMR T2 spectra.37 Among these experiments, cores were always kept dry to make sure that all the signals were coming from the thickener. On the basis of this, the thickener was adsorbed in the core, which is supposed to the main reason for wettability alteration. Second, as Figure 10 shows, the T2 spectra area for various core samples present a strong regularity. With the increasing of thickener concentration, the T2 spectra area is becoming larger and larger. That is to say, with the increase of silicohydride G

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

Figure 12. EDS of core surfaces: (A) ER-1 treated with 0% thickener, (B) ER-2 treated with 1% thickener, (C) ER-3 treated with 2% thickener, (D) ER-4 treated with 3% thickener.

surface was evaluated by contact angle measurement. For the adsorption in pores, spontaneous imbibition was introduced here to estimate the wettability alteration inside the pores in core samples. The imbibition was carried out within a brine−oil-core system. After taking the NMR T2 spectra test, MR-1, MR-2, MR-3, and MR-4 were saturated with oil, and imbibition tests were conducted. Oil and brine described in section 2.1 were employed under the condition of 55 °C. During imbibition, the oil recovery with time is shown in Figure 13. From Figures 13 and 14, the oil recovery from imbibition all reached to maximum at the 10th day. With the increasing concentration of thickener, oil recovery from imbibition is decreasing, which is corresponding with the wettability alteration. MR-1 with 0% thickener achieved 6.31% of OOIP, and MR-2 with 1% thickener achieved 6.06%. It is not an

In addition, the thickener is composed of Si, C, O and H. From Figure 12, the total percentage of atomic content of Si, C, O is measured by EDS. According to Figure 12b, the total percentage of atomic content is 86.59% for ER-1 with 0% thickener. ER-2 with 1% thickener, ER-3 with 2% thickener, and ER-4 with 3% thickener increased the total percentage of atomic content to 89.37%, 90.63%, and 95.38%, respectively. Therefore, with the increasing content of thickener in SC-CO2 fracturing fluid, the percentage of Si, C, and O content was increased. This can confirm that the adsorbed material on the core surface is silicohydride thickener, as well. 3.4. Oil Recovery by Spontaneous Imbibition after the Treatment of SC-CO2 Fracturing Fluid. After treatment with SC-CO2 fracturing fluid, the adsorption of thickener happened both on the sample surface and pores in microscale. The surface wettability caused by adsorption on the sample H

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

(1) The thickener of SC-CO2 fracturing fluid was responsible for core wettability alteration. With the increasing thickener contents of fracturing fluid, cores turned to be intermediate and slightly water-wet from strongly water-wet, which was unfavorable for oil production. (2) The filter loss of the SC-CO2 fracturing fluid also affected core wettability alteration. The greater the amount of filtration, the bigger the contact angle changes to oil-wet, which meant more damage to the reservoir matrix. (3) Initial reservoir permeability was one of the main factors which could affect the wettability alteration as well. Lower permeability cores which consist of more micrometer to nanometer pores were more likely to form adsorption retention in pores and throats, which made treated cores much more oleophilic. That is to say, the low permeability reservoir matrix was much easier to be damaged in the process of SC-CO2 fracturing. (4) By taking a group of NMR T2 tests, silicohydride thickener adsorption retention in pores was confirmed to be the main wettability alteration mechanism for SC-CO2 fracturing fluid. Furthermore, with the increasing contents of thickener, the adsorption first occurred in relatively small pores. After small pores were close to saturation adsorption, the adsorption gradually transferred to relatively large pores. (5) SEM was used to examine the adsorption characteristics and distribution of thickener on the rock surface. With the increase contents of thickener, the thickener spots were first sporadically scattered on the mineral surface. Then, it was much more densely absorbed on the mineral surface, which almost formed a coating over the mineral surface. Finally, the thickener was fully absorbed on the mineral surface and forms a uniform adsorption layer with many liquid drops, which makes the wettability further turning to oil-wet. Meanwhile, the adsorption material was confirmed to be the silicohydride thickener by EDS. (6) Spontaneous imbibition tests were conducted to evaluate the impact of wettability alteration inside of the core sample. With the increase of thickener contents, oil recovery of cores became lower and lower, which certified the wettability alteration caused by too much thickener in SC-CO2 fracturing fluid would impede the oil flow.

Figure 13. Oil recovery versus time in spontaneous imbibition.

Figure 14. Oil recovery from imbibition versus core wettability.

obvious variation between the 0% thickener and the 1% thickener because of slight wettability alteration in cores. The slight wettability alteration corresponded to small adsorption in the 1% thickener fracturing fluid system, as Figures 9 and 10 show. Therefore, this slight difference of the OOIP between the 0% thickener and the 1% thickener further proved that the internal hydrophobic of cores treated with the 1% thickener are stronger than the one treated with the 0% thickener, while this cannot be observed in contact angle measurement. MR-3 with 2% thickener and MR-4 with 3% thickener achieved an oil recovery of 4.75% and 4.02%, respectively, which means much higher thickener adsorption and stronger oleophilic than former cores. That is to say, SC-CO2 fracturing fluid with too much thickener would impede the oil flow.

■

AUTHOR INFORMATION

Corresponding Authors

*E-mail: [email protected]. Tel: +86-532-86981183 (C.D.). *E-mail: [email protected]. Tel: +86-532-86981183 (Y.S.). ORCID

Yongpeng Sun: 0000-0003-3836-5083

4. CONCLUSIONS A group of contact angle measurements were proposed to investigate the surface wettability alteration on core samples. The NMR, SEM, and EDS techniques were used to validate and explain the reason for wettability alteration. Moreover, a spontaneous imbibition test was taken to investigate the internal wettability alteration in cores and the impact of wettability alteration on oil production was defined. The main conclusions drawn from this study are summarized below:

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 Climb Taishan Scholar Program in Shandong Province (tspd20161004). I

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX

Article

Energy & Fuels

■

Reservoirs in Changqing Oilfield. Liaoning Chem. Ind. 2013, 42 (09), 1125−−1127. (20) Morrow, N. R.; Lim, H. T.; Ward, J. S. Effect of Crude-OilInduced Wettability Changes on Oil Recovery. SPE Form. Eval. 1986, 1 (1), 89−103. (21) Donaldson, E. C. Oil-Water-Rock Wettability Measurement. Am. Chem. Soc., Div. Pet. Chem., Prepr. 1981, 26, 1. (22) Ghaedi, M.; Masihi, M.; Heinemann, Z. E.; Ghazanfari, M. H. Using the Recovery-Curve Method for In Situ Wettability Determination in a Fractured Porous Medium. Energy Technology 2015, 3 (5), 518−526. (23) Gupta, R.; Mohanty, K. K. Wettability Alteration of Fractured Carbonate Reservoirs. In SPE Symposium on Improved Oil Recovery, Tulsa, OK, April 20−23, 2008; Society of Petroleum Engineers, 2008; SPE-113407-MS. (24) Carr, H. Y.; Purcell, E. M. Effects of Diffusion on Free Precession in Nuclear Magnetic Resonance Experiments. Phys. Rev. 1954, 94 (3), 630−638. (25) Meiboom, S.; Gill, D. Modified Spin-Echo Method for Measuring Nuclear Relaxation Times. Rev. Sci. Instrum. 1958, 29 (8), 688−691. (26) Ronczka, M.; Müllerpetke, M. Optimization of CPMG Sequences to Measure NMR Transverse Relaxation Time T2 in Borehole Applications. Geosci. Instrum., Methods Data Syst. 2012, 1 (2), 197−208. (27) Gonzalez, V.; Jones, M.; Taylor, S. E. Spin−Spin Relaxation Time Investigation of Oil/Brine/Sand Systems. Kinetics, Effects of Salinity, and Implications for Wettability and Bitumen Recovery. Energy Fuels 2016, 30 (2), 844−853. (28) Feng, C.; Shi, Y.; Hao, J.; Wang, Z.; Mao, Z.; Li, G.; Jiang, Z. Nuclear Magnetic Resonance Features of Low-permeability Reservoirs With Complex Wettability. Pet. Explor. Dev. 2017, 44 (2), 274−279. (29) He, Z.; Li, G.; Tian, S.; Wang, H.; Shen, Z.; Li, J. SEM Analysis on Rock Failure Mechanism by Supercritical CO 2 jet Impingement. J. Pet. Sci. Eng. 2016, 146, 111−120. (30) Sharma, T.; Iglauer, S.; Sangwai, J. S. Silica Nanofluids in an Oilfield Polymer Polyacrylamide: Interfacial Properties, Wettability Alteration and Applications for Chemical Enhanced Oil Recovery. Ind. Eng. Chem. Res. 2016, 55 (48), 12387−12397. (31) Jin, J.; Wang, Y.; Wang, K.; Ren, J.; Bai, B.; Dai, C. The Effect of Fluorosurfactant-modified Nano-silica on the Gas-wetting Alteration of Sandstone in a CH 4 -liquid-core System. Fuel 2016, 178, 163−171. (32) Mirzaei-Paiaman, A.; Masihi, M. Scaling of Recovery by Cocurrent Spontaneous Imbibition in Fractured Petroleum Reservoirs. Energy Technology 2014, 2 (2), 166−175. (33) Dai, C.; Wang, X.; Li, Y.; Lv, W.; Zou, C.; Gao, M.; Zhao, M. Spontaneous Imbibition Investigation of Self-Dispersing Silica Nanofluids for Enhanced Oil Recovery in Low-Permeability Cores. Energy Fuels 2017, 31 (3), 2663−2668. (34) Lan, Q.; Ghanbari, E.; Dehghanpour, H.; Hawkes, R. Water Loss Versus Soaking Time: Spontaneous Imbibition in Tight Rocks. Energy Technology 2014, 2 (12), 1033−1039. (35) Gupta, R.; Mohanty, K. K. Wettability Alteration Mechanism for Oil Recovery From Fractured Carbonate Rocks. Transp. Porous Media 2011, 87 (2), 635−652. (36) Vatanparast, H.; Alizadeh, A. H.; Bahramian, A.; Bazdar, H. Wettability Alteration of Low-permeable Carbonate Reservoir Rocks in Presence of Mixed Ionic Surfactants. Pet. Sci. Technol. 2011, 29 (18), 1873−1884. (37) Plee, D.; Borg, F.; Gatineau, L.; Fripiat, J. J. High-resolution Solid-state Aluminum-27 and Silicon-29 Nuclear Magnetic Resonance Study of Pillared Clays. J. Am. Chem. Soc. 1985, 107 (8), 2362−2369.

REFERENCES

(1) Mirchi, V.; Saraji, S.; Goual, L.; Piri, M. Dynamic Interfacial Tension and Wettability of Shale in the Presence of Surfactants at Reservoir Conditions. Fuel 2015, 148, 127−138. (2) Bertoncello, A.; Honarpour, M. M. Standards for Characterization of Rock Properties in Unconventional Reservoirs: Fluid Flow Mechanism Quality Control and Uncertainties. In SPE Annual Technical Conference and Exhibition, New Orleans, LA, Sept 30−Oct 2, 2013; Society of Petroleum Engineers, 2013; SPE-166470-MS. (3) Xu, Z.; Li, Z.; Wang, C.; Adenutsi, C. D. Experimental Study on Microscopic Formation Damage of low Permeability Reservoir Caused by HPG Fracturing Fluid. J. Nat. Gas Sci. Eng. 2016, 36, 486−495. (4) Ribeiro, L. H.; Li, H.; Bryant, J. E. Use of a CO2-Hybrid Fracturing Design to Enhance Production From Unpropped-Fracture Networks. SPE Prod. Oper. 2017, 32 (01), 28−40. (5) Middleton, R. S.; Carey, J. W.; Currier, R. P.; Hyman, J. D.; Kang, Q.; Karra, S.; Jiménez-Martínez, J.; Porter, M. L.; Viswanathan, H. S. Shale gas and Non-aqueous Fracturing Fluids: Opportunities and Challenges for Supercritical CO 2. Appl. Energy 2015, 147 (3), 500− 509. (6) Yu, W.; Lashgari, H. R.; Wu, K.; Sepehrnoori, K. CO 2 Injection for Enhanced oil Recovery in Bakken Tight oil Reservoirs. Fuel 2015, 159 (1), 354−363. (7) Brown, D. W. A Hot Dry Rock Geothermal Energy Concept Utilizing Supercritical CO2 Instead of Water. In Proceedings of the Twenty-Fifth Workshop on Geothermal Reservoir Engineering, Stanford University, Standford, CA, January 24−26, 2000; Stanford Geothermal Program, 2000; SGP-TR-165, pp 233−238. (8) Huang, Z.; Shi, C.; Xu, J.; Kilic, S.; Enick, R. M.; Beckman, E. J. Enhancement of the Viscosity of Carbon Dioxide Using Styrene/ Fluoroacrylate Copolymers. Macromolecules 2000, 33 (15), 5437− 5442. (9) Liu, H.; Wang, F.; Zhang, J.; Meng, S.; Duan, Y. Fracturing with Carbon Dioxide: Application Status and Development Trend. Pet. Explor. Dev. 2014, 41 (4), 513−519. (10) Ishida, T.; Aoyagi, K.; Niwa, T.; Chen, Y.; Murata, S.; Chen, Q.; Nakayama, Y. Acoustic Emission Monitoring of Hydraulic Fracturing Laboratory Experiment With Supercritical and Liquid CO2. Geophys. Res. Lett. 2012, 39 (16), L16309. (11) Zhang, X.; Lu, Y.; Tang, J.; Zhou, Z.; Liao, Y. Experimental Study on Fracture Initiation and Propagation in Shale Using Supercritical Carbon Dioxide Fracturing. Fuel 2017, 190, 370−378. (12) Li, Z.; Yang, X.; Xia, B.; Wu, Z.; Wang, H.; Guo, Q. A new Nonguar gum Polymer Fracturing Fluid. Drill. Fluid Completion Fluid 2014, 31 (5), 85−88. (13) Chen, F.; Liu, Y.; Wang, D. Y. Studies in Formation Damages Caused by Cationic Surfactant Base Fracturing Fluids. Drill. Fluid Completion Fluid 2007, 24 (06), 62−65. (14) Zhang, J.; Zhang, M.; Zhang, S.; Bai, B.; Gao, Z. Development and Field Pilot of a Novel Viscoelastic Anionic-Surfactant (VAS) Fracturing Fluid. In SPE Western Regional Meeting, Anaheim, CA, May 27−29, 2010; Society of Petroleum Engineers, 2010; SPE-133596-MS. (15) Bai, B.; Elgmati, M.; Zhang, H.; Wei, M. Rock Characterization of Fayetteville Shale gas Plays. Fuel 2013, 105 (3), 645−652. (16) Zhou, J.; Xiangyi, Y. I.; Yuan, L. U.; Qiu, X.; Jinliang, Y. E. Experimental and Mechanism Research of Damage of Clean Fracturing Fluids to Coalbed Methane. Sci. Technol. Rev. 2015, 33 (4), 72−−75. (17) Shariatpanahi, S. F.; Strand, S.; Austad, T. Evaluation of WaterBased Enhanced Oil Recovery (EOR) by Wettability Alteration in a Low-Permeable Fractured Limestone Oil Reservoir. Energy Fuels 2010, 24 (11), 5997−6008. (18) Cai, Y.; Xiaorong, L. I.; Shi, M.; Yang, L.; Liu, X.; Feipeng, W. U. Research on the Adaptability of Polymeric Nanospheres Flooding in Extra-low Permeability Reservoir in Changqing Oilfield. Oil Drill. Prod. Technol. 2013, 35 (4), 88−93. (19) Wei, Q.; Zhang, W. J.; Feng, X. D.; University, X. S. Research on the Profile Control Technology for Low Permeability Fractured J

DOI: 10.1021/acs.energyfuels.7b02534 Energy Fuels XXXX, XXX, XXX−XXX