ORCID Profile
0000-0003-0951-1133
Current Organisation
Curtin University
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Publisher: Elsevier BV
Date: 12-2018
Publisher: Elsevier BV
Date: 10-2019
Publisher: Elsevier BV
Date: 02-2020
Publisher: Elsevier BV
Date: 2021
Publisher: SPE
Date: 11-08-2015
DOI: 10.2118/174592-MS
Abstract: In recent years, low salinity waterflooding (LSWF) has been a promising technique to recover oil in sandstone reservoirs. In view of research results for the last decade, it is acknowledged that substantial oil recovery beyond conventional waterflooding from sandstone is wettability alteration. However, the major contributor to wettability alteration is still uncertain. Therefore, this paper investigates this major mechanism and shows how it is involved in the process of IOR. Rock and oil surface chemistry were tested to explain the influence of zeta potential on the disjoining pressure. Coreflood experiments with permeability less than 1mD were carried out and the impact of different wettabilities ranging from strong water-wet to slight water-wet on LSWF recovery was investigated with combination of thermodynamic theory. Relative permeability curves were obtained by history matching the corefloods experiments for both slight water-wet and strong water-wet cores with consideration of salinity effect. Thermodynamics of wettability by low salinity waterflooding was analyzed to characterize the surface forces between the surfaces of oil/water and water/rock. Zeta potential results showed that decreasing alent cations and salinity makes the electrical charges at both oil/brine and brine/rock interfaces become strongly negative, which results in elevation of the repulsive forces between oil and rock, and as a result the rock turns more water-wet, which was confirmed by thermodynamics characterization. Corefloods experiments showed that a high potential in slight water-wet reservoirs can be achieved by low salinity waterflooding due to the double layer expansion. The relative permeability curves obtained by history matching showed that LSW improves oil recovery by accelerating oil production (relative perm changes) and reducing residual oil saturation in slight water-wet rock but not in strong water-wet rock. Thermodynamics of wettability analysis indicated that the mechanism of low salinity waterflooding might be interpreted by disjoining pressure calculation. In conclusion, double layer expansion caused by highly negative zeta potential as a result of lower salinity and alent cation plays a major role in recovering additional oil. The low salinity waterflooding EOR-Effect might be interpreted by disjoining pressure calculation. These findings can help in composition design of low salinity water to maintain higher potential to recover oil in oil field.
Publisher: Elsevier BV
Date: 12-2016
Publisher: Elsevier BV
Date: 05-2021
Publisher: Elsevier BV
Date: 04-2020
Publisher: American Chemical Society (ACS)
Date: 30-07-2019
Publisher: MDPI AG
Date: 26-06-2018
DOI: 10.3390/EN11071666
Publisher: Elsevier BV
Date: 04-2021
Publisher: Elsevier BV
Date: 06-2020
Publisher: Elsevier BV
Date: 11-2016
Publisher: American Chemical Society (ACS)
Date: 04-05-2020
Publisher: Elsevier BV
Date: 06-2017
Publisher: Elsevier BV
Date: 03-2019
Publisher: Elsevier BV
Date: 06-2022
Publisher: American Chemical Society (ACS)
Date: 08-10-2021
Publisher: Elsevier BV
Date: 11-2016
Publisher: Elsevier BV
Date: 04-02-2010
Publisher: American Chemical Society (ACS)
Date: 21-09-2020
Publisher: MDPI AG
Date: 08-03-2020
DOI: 10.3390/MOLECULES25051214
Abstract: The hydraulic fracturing technique remains essential to unlock fossil fuel from shale oil reservoirs. However, water imbibed by shale during hydraulic fracturing triggers environmental and technical challenges due to the low flowback water recovery. While it appears that the imbibition of fracturing fluid is a complex function of physico-chemical processes in particular capillary force which is associated with wettability of oil-brine-shale, the controlling factor(s) to govern the wettability is incomplete and the literature data in this context is missing. We thus measured the adsorption/desorption of asphaltenes on silica surface in the presence of brines using quartz crystal microbalance with dissipation (QCM-D). We detected zeta potential of asphaltene-brine and brine-silica systems and calculated the disjoining pressures of the asphaltene-brine-silica system in the case of different salinity. Moreover, we performed a geochemical study to quantify the variation of surface chemical species at asphaltene and silica surfaces with different pH values and used the chemical force microscope (CFM) method to quantify the effect of pH on intermolecular forces. Our results show that lowering salinity or raising pH reduced the adhesion force between asphaltene and silica surface. For ex le, at a pH value of 6.5, when the concentration of injected water is reduced from 1000 mM to 100 mM and 10 mM, the adhesion force decreased by approximately 58% and 66%, respectively. In addition, for the 100 mM NaCl solution, when the pH value increased from 4.5 to 6.5 and 9, the adhesion force decreased by approximately 56% and 87%, respectively. Decreased adhesion forces between asphaltene and the silica surface could promote the desorption of asphaltene from the silica surface, resulting in a negative zeta potential for both asphaltene-silica and brine-silica interfaces and a shift of wettability towards water-wet characteristic. During such a process, -NH+ number at asphaltene surfaces decreases and the bonds between -NH+ and SiO− break down, to further interpret the formation of a thinner asphaltene adlayer on the rock surface. This study proposes a reliable theoretical basis for the application of hydraulic fracturing technology, and a facile and possible manipulation strategy to increase flowback water from unconventional reservoirs.
Publisher: American Chemical Society (ACS)
Date: 24-04-2019
Publisher: American Chemical Society (ACS)
Date: 15-02-2022
Publisher: Elsevier BV
Date: 06-2020
Publisher: American Chemical Society (ACS)
Date: 05-01-2023
Publisher: SPE
Date: 25-10-2016
DOI: 10.2118/182402-MS
Abstract: This paper presents a systematic assessment of the potential of low salinity water flooding for the Dong-He-Tang reservoir in the Tarim Oilfield, China. This reservoir has a high reservoir temperature of 140 °C, high formation water salinity of 142,431 ppm total dissolved solids and an in-situ oil viscosity of 2.2 cp. Our laboratory evaluation included contact angle tests, and spontaneous imbibition and core-flooding experiments using representative core s les from the reservoir. Contact angle tests were conducted at various temperatures (60, 100 and 140 °C) and pressures (20, 30, 40 and 50 MPa). Core-flooding experiments were conducted under the reservoir temperature of 140 °C. Formation brine and low salinity water (100 times diluted formation brine) were used in the experiments. Contact angle and spontaneous imbibition experiments showed that low salinity water shifted the reservoir wettability towards more water-wet. In addition, spontaneous imbibition experiments showed that low salinity water recovered significantly more oil than high salinity water. Furthermore, corefloods were conducted using low salinity water under tertiary and secondary modes. Experimental results were history matched to derive relative permeability curves and capillary pressure curves while considering the non-uniqueness of such history-matching. Results showed that compared to high salinity water flooding, low salinity water shifted relative permeability curves towards lower residual oil saturation, showing a higher oil relative permeability and lower water relative permeability at the same water saturation. The parameters derived from laboratory experiments were used as input for reservoir simulation models to investigate the potential of low salinity water flooding in the reservoir using two layered box models. Findings showed that low salinity water accelerated oil production by increasing the oil relative permeability, thus resulting in a higher recovery factor with only a fraction of pore volume of low salinity water injection. Implications of these findings, such as slug size, salinity of injected brine, non-uniqueness of derived relative permeability curves on incremental oil recovery were assessed. This paper is novel in the following aspects. First, the potential of low salinity water at a high reservoir temperature of 140 °C was systematically investigated. Second, laboratory experiments showed that low salinity water changed the reservoir wettability towards more water-wet, which is consistent with the observed shift in the relative permeability curves derived from core-scale numerical simulation. Third, the potential of the low salinity water in such high temperature environments was assessed using reservoir simulation based on the input from laboratory experiments.
Publisher: Elsevier BV
Date: 04-2020
Publisher: Elsevier BV
Date: 12-2017
Publisher: Elsevier BV
Date: 08-2019
Publisher: Elsevier BV
Date: 10-2017
Publisher: Springer Science and Business Media LLC
Date: 24-07-2018
Publisher: Elsevier BV
Date: 11-2018
Publisher: American Chemical Society (ACS)
Date: 09-01-2019
Publisher: American Chemical Society (ACS)
Date: 18-01-2019
Publisher: Elsevier BV
Date: 09-2016
Publisher: Society of Petroleum Engineers (SPE)
Date: 31-12-2018
DOI: 10.2118/190876-PA
Abstract: Reservoir heterogeneity plays a critical role in determining the success of enhanced-oil-recovery (EOR) processes, but its effect rarely has been comprehensively quantified in the laboratory. This work presents the results of an experimental study on the effects of various carbon dioxide (CO2) injection modes on immiscible-flooding performance in heterogeneous-sandstone porous media. Thus, the results of this study can be insightful in overcoming the current challenges in capturing the importance of geological uncertainties in current and future EOR projects. Coreflooding experiments were conducted for n-decane/synthetic-brine/CO2 systems at a 9.6-MPa backpressure and at 343 K to attain immiscible-flooding conditions [minimum-miscibility pressure (MMP) of CO2 in n-decane is 12.4 MPa]. For this purpose, two sets of heterogeneous-sandstone core s les were assembled with heterogeneity either parallel to (layered s les) or perpendicular to (composite s les) the flow. The results obtained for both composite and layered core s les indicated that heterogeneity tremendously influences the outcome of the CO2 EOR. Oil recovery decreases dramatically with an increase in the heterogeneity level or permeability ratio (PR). In addition, the crossflow in the layered core s le is found to have a noticeable effect on the ultimate oil recovery (increasing oil recovery up to 5%). Also, it is worth noting that for the composite s les, when we arranged the plugs by putting the low-permeability segments closer to the s le outlets, the recovery factor increased. However, regardless of the segment arrangements, the recoveries in composite cores are lower than those obtained from the homogeneous core s le.
Publisher: Elsevier BV
Date: 07-2019
Publisher: MDPI AG
Date: 09-12-2019
DOI: 10.3390/EN12244688
Abstract: Excessive water production is becoming common in many gas reservoirs. Polymers have been used as relative permeability modifiers (RPM) to selectively reduce water production with minimum effect on the hydrocarbon phase. This manuscript reports the results of an experimental study where we examined the effect of initial rock permeability on the outcome of an RPM treatment for a gas/water system. The results show that in high-permeability rocks, the treatment may have no significant effect on either the water and gas relative permeabilities. In a moderate-permeability case, the treatment was found to reduce water relative permeability significantly but improve gas relative permeability, while in low-permeability rocks, it resulted in greater reduction in gas relative permeability than that of water. This research reveals that, in an RPM treatment, more important than thickness of the adsorbed polymer layer ( e ) is the ratio of this thickness on rock pore radius ( e r ).
Publisher: Elsevier BV
Date: 05-2019
Publisher: Elsevier BV
Date: 06-2023
Publisher: Elsevier BV
Date: 09-2019
Publisher: Elsevier BV
Date: 11-2019
Publisher: American Chemical Society (ACS)
Date: 04-10-2018
Publisher: Elsevier BV
Date: 03-2018
Publisher: Elsevier BV
Date: 11-2020
Publisher: American Chemical Society (ACS)
Date: 22-11-2017
Publisher: Elsevier BV
Date: 04-2018
Publisher: American Chemical Society (ACS)
Date: 25-01-2021
Publisher: MDPI AG
Date: 22-12-2019
DOI: 10.3390/EN13010077
Abstract: While the effect of polar-oil component on oil-brine-carbonate system wettability has been extensively investigated, there has been little quantitative analysis of the effect of non-polar components on system wettability, in particular as a function of pH. In this context, we measured the contact angle of non-polar oil on calcite surface in the presence of 10,000 ppm NaCl at pH values of 6.5, 9.5 and 11. We also measured the adhesion of non-polar oil group (–CH3) and calcite using atomic force microscopy (AFM) under the same conditions of contact angle measurements. Furthermore, to gain a deeper understanding, we performed zeta potential measurements of the non-polar oil-brine and brine-calcite interfaces, and calculated the total disjoining pressure. Our results show that the contact angle decreases from 125° to 78° with an increase in pH from 6.5 to 11. AFM measurements show that the adhesion force decreases with increasing pH. Zeta potential results indicate that an increase in pH would change the zeta potential of the non-polar oil-brine and calcite-brine interfaces towards more negative values, resulting in an increase of electrical double layer forces. The total disjoining pressure and results of AFM adhesion tests predict the same trend, showing that adhesion forces decrease with increasing pH. Our results show that the pH increase during low-salinity waterflooding in carbonate reservoirs would lift off non-polar components, thereby lowering residual oil saturation. This physiochemical process can even occur in reservoirs with low concentration of polar components in crude oils.
Publisher: Elsevier BV
Date: 06-2023
Publisher: Elsevier BV
Date: 12-2014
Publisher: Elsevier BV
Date: 04-2023
Publisher: Elsevier BV
Date: 07-2017
Publisher: IOP Publishing
Date: 10-2020
DOI: 10.1088/1755-1315/570/3/032010
Abstract: The natural-fracture network and a large part of hydraulic fractures are poorly supported, and the conductivity of the natural-fracture network is highly sensitive to stress and strain during the production stage. In this work, we aimed to understand the impact of mode I (tensile) and mode II (shear) fractures on fracture-gas permeability as a function of effective stress in Long Ma Xi shale in the Dragon Horse Creek Group in Western China. Experimental results showed that the two-mode fracture tortuosity and width of shale were opposite those of sandstone. Our results implied that in Long Ma Xi shale, mode I fractures likely contributed significantly to early-stage high well productivity, with low effective stress, and mode II fractures may contribute to well productivity after the initial stage of gas production, with relatively high effective stress.
Publisher: SPE
Date: 11-08-2015
DOI: 10.2118/174584-MS
Abstract: Low salinity waterflood (LSF) is a promising improved oil recovery (IOR) technology. Although, it has been demonstrated that LSF is an efficient IOR method for many sandstone reservoirs, the potential of LSF in tight oil reservoir is not well-established. This paper presents a systematic evaluation of the potential of low salinity waterfloding for the tight reservoirs in Jiyuan Oilfield, China. This investigation pushes the application envelope of low salinity waterflooding towards the reservoir with low permeability (lower than 0.5mD), formation salinity of up to 45,180ppm, reservoir temperature of 70°C and in-situ oil viscosity of 0.6 cp. Our laboratory evaluation included zeta potential tests for interface of oil/brine and brine/rock, thermodynamic analysis through disjoining pressure calculation, corefloods using representative core s les. Thermodynamic analysis showed that decreasing alent cations and salinity makes the electrical charges at both oil/brine and brine/rock interfaces become strongly negative, which enhanced the repulsive forces between oil and rock due to the double electric layer expansion. As a result, the rock turns more water-wet. Secondary corefloods were conducted with two different brines, which include shallow aquifer water and ion tuning water with consideration of field application. Coreflooding Experimental results were history matched to obtain the relative permeability curves. Results showed that compared to shallow aquifer water, low-salinity water exhibited a higher oil relative permeability and lower water relative permeability at the same water saturation and a lower residual oil saturation to water. Laboratory results were input into a reservoir simulator to investigate the potential of low-salinity water flood in Jiyuan oilfield. It showed that suitably formulated ion tuning water (ITW) has the potential to accelerate oil production and improve displacement efficiency, thus resulting in a higher recovery factor with only a fraction of pore volume of low-salinity water injected. To conclude, this paper demonstrates that ITWF has a good potential as an IOR/EOR technology in tight reservoirs, the key points are described as follows. Firstly, the mechanism of ITWF was interpreted by thermodynamics of wettability. Secondly, laboratory experiments have shown that ITWF could improve oil recovery by accelerating the oil production rate and decrease the residual oil production. Thirdly, the potential of ITWF in a tight oil reservoir in Jiyuan oilfield is investigated using a mechanistic model based on input data of laboratory experiments.
Publisher: Elsevier BV
Date: 04-2019
Publisher: American Chemical Society (ACS)
Date: 07-09-2017
Publisher: Elsevier BV
Date: 07-2020
Publisher: American Chemical Society (ACS)
Date: 12-11-2019
Publisher: Elsevier BV
Date: 09-2018
Publisher: Elsevier BV
Date: 09-2016
Publisher: Elsevier BV
Date: 08-2019
Publisher: Elsevier BV
Date: 2018
Publisher: Elsevier BV
Date: 05-2019
Publisher: Informa UK Limited
Date: 13-04-2012
Publisher: Elsevier BV
Date: 03-2021
Publisher: Elsevier BV
Date: 10-2021
Publisher: MDPI AG
Date: 06-11-2019
DOI: 10.3390/EN12224225
Abstract: Water uptake induced by fluid–rock interaction plays a significant role in the recovery of flowback water during hydraulic fracturing. However, the existing accounts fail to fully acknowledge the significance of shale anisotropy on water uptake typically under in situ reservoir temperature. Thus we investigated the shale-hydration anisotropy using two sets of shale s les from the Longmaxi Formation in Sichuan Basin, China, which are designated to imbibe water parallel and perpendicular to shale bedding planes. All the s les were immersed in distilled water for one to five days at 80 °C or 120 °C. Furthermore, s les’ topographical and elemental variations before and after hydration were quantified using energy-dispersive spectroscopy–field-emission scanning electron microscopy. Our results show that shale anisotropy and imbibition time strongly affect the width of pre-existing micro-fracture in hydrated s les. For imbibition parallel to lamination, the width of pre-existing micro-fracture initially decreases and leads to crack-healing. Subsequently, the crack surfaces slightly collapse and the micro-fracture width is enlarged. In contrast, imbibition perpendicular to lamination does not generate new micro-fracture. Our results imply that during the flowback process of hydraulic fracturing fluid, the shale permeability parallel to bedding planes likely decreases first then increases, thereby promoting the water uptake.
Publisher: European Association of Geoscientists & Engineers
Date: 2019
Publisher: SPE
Date: 25-10-2020
DOI: 10.2118/196456-MS
Abstract: The microseismicity associated with hydraulic fracturing in unconventional reservoir (i.e. shale gas play) has been investigated in the past several decades. Few experimental studies with respect to the focal mechanism and stress inversion was conducted, especially for Glutenite reservoir. In this study, the glutenite core was taken from the underground of 2600 m. Next, we performed scaled hydraulic fracturing tests on the cubic core (50×50×50mm) under geological principle stress condition in true tri-axial stress cell. Meanwhile, we monitored wellbore and pore pressure, and micro-seismic events during the fracture propagation from six faces of the cubic rock. Micro-seismic survey and events were interpreted to identify the induced fractures distribution in three dimension. Source mechanism and stress inversion were analyzed by moment tensor decomposition. The correlation of failure plane from microseismicity and tested s le implied that the microseismic events were accurately localized. The distribution of microseismic events from secondary and reopening tests indicated that the hydraulic fracturing induced microseismicity are mainly caused by significant tip effect (i.e. reactivate preexisting natural fractures). Based on source mechanism analysis, we found that the most of the failure are dominated by double-couple (DC). The correlation between original principle stress state and the one from STESI inversion indicated that the direction of principle stresses, especially for σ2 and σ3 inversed from reopening test, can be highly influenced by the hydraulic induced fracture or weak planes during secondary fracturing test.
Publisher: Springer Science and Business Media LLC
Date: 06-12-2018
DOI: 10.1038/S41598-018-35878-3
Abstract: Injecting CO 2 into oil reservoirs appears to be cost-effective and environmentally friendly due to decreasing the use of chemicals and cutting back on the greenhouse gas emission released. However, there is a pressing need for new algorithms to characterize oil/brine/rock system wettability, thus better predict and manage CO 2 geological storage and enhanced oil recovery in oil reservoirs. We coupled surface complexation/CO 2 and calcite dissolution model, and accurately predicted measured oil-on-calcite contact angles in NaCl and CaCl 2 solutions with and without CO 2 . Contact angles decreased in carbonated water indicating increased hydrophilicity under carbonation. Lowered salinity increased hydrophilicity as did Ca 2+ . Hydrophilicity correlates with independently calculated oil-calcite electrostatic bridging. The link between the two may be used to better implement CO 2 EOR in fields.
Publisher: American Chemical Society (ACS)
Date: 30-09-2019
Publisher: American Chemical Society (ACS)
Date: 24-02-2020
Publisher: Elsevier BV
Date: 10-2021
Publisher: American Chemical Society (ACS)
Date: 15-10-2020
Publisher: Elsevier BV
Date: 12-2020
Publisher: American Chemical Society (ACS)
Date: 25-08-2021
Publisher: Elsevier BV
Date: 09-2021
Publisher: Elsevier BV
Date: 10-2019
Location: China
No related grants have been discovered for Quan Xie.