ENERGY & FUELS
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2024
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IF 5.2
Qi Gao,Xingguang Xu,Shuai Liu,Athumani Omari Mmbuji,Yunkun Wu
CO2 foam has been identified as having significant applications in carbon capture utilization and storage (CCUS). This is attributed to its proven capability to mitigate channeling during CO2 injection effectively; meanwhile, the majority of injected CO2 can be safely stored in reservoirs through geo-sequestration. However, the high injection pressure and poor foam stability severely affect the wide employment of CO2 foam flooding. In this study, comprehensive investigations on a novel CO2-responsive foam (CRF) with desirable injectivity and noticeable longevity are presented. This novel foam system employs lauryl ether sulfate sodium (LES) and diethylenetriamine (DETA) as foaming agents, and it exhibits notable reversible CO2-responsive properties. This property enables the fluid to transit between low and high-viscosity states, enhancing foam injection performance and reducing the injection pressure. CRF is less detrimental to reservoirs compared to conventional polymer-enhanced foam (PEF) due to its ability to switch between gel-forming and gel-breaking phases using CO2/N2. In addition, rheological tests demonstrate that CRF exhibits superior high shear tolerance compared to PEF. Moreover, CRF shows greater stability and higher salt resistance compared to PEF. At a NaCl concentration of 5 × 104 mg/L, the half-life of CRF (152 min) was nearly 13 times longer than that of PEF (11 min). It is noted that CRF exhibits a higher resistance factor in high-permeability cores compared to low-permeability cores, indicating its outstanding capacity to block the channels and mitigate CO2 breakthrough. The results of the enhanced oil recovery (EOR) experiments indicated that CRF is capable of displacing more oil than PEF in fractured cores with identical experimental conditions. It is believed that CRF may be applied as a viable CCUS technique and may enlighten investigations on novel CCUS strategies.
研究领域:
石油工程
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环境科学
✓ 已验证
产品关联
DOI
高影响因子
JOURNAL OF DISPERSION SCIENCE AND TECHNOLOGY
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2020
·
IF 1.701
Jirui Zou,Xiangan Yue,Jie Dong,Minglu Shao,Liqi Wang,Jun Gu,Weijie An
To solve the contradiction between the injectability of the profile control agent and its profile control ability in low-permeability reservoirs, a novel in-situ polymeric microsphere profile control agent is proposed. In-situ-polymeric microsphere (ISPM) emulsion was injected into the formation by polymerization to form microspheres for profile control. The emulsion was composed of divinylbenzene, acrylamide monomer, surfactant fatty acid polyoxyethylene ether sulfate, sorbitan oleate and p-hydroxyanisole. An ISPM particle diameter of 1.88 to 30.60 μm was achieved by adjusting the amount of Span80. The ISPM emulsion polymerization time was set to a maximum of 8.4 hours to ensures that the microsphere emulsion could be successfully injected into the formation. Polymerization reaction time increased with the increase of salinity. pH has no significant effect on the reaction time in the range of 5 to 8. Fourier transform infrared spectroscopy (FT-IR) experiments showed that the ISPM emulsion could be polymerized in tiny pores to form microspheres. Furthermore, multipoint pressure measurement experiment and electron microscopy results showed that the ISPM emulsion presented good injectability in low-permeability cores, and the microspheres formed after emulsion polymerization achieved deep plugging in cores. The injectability and blocking effect of the core with ISPM was found to be better than with microspheres (61.7%) for the blocking rate of the core at 10–15 cm deep reached 81.55%. The double-layer heterogeneous core flooding experiments showed that ISPM could expand the sweep volume of subsequent injection fluids and achieve improved oil production and water control. The composite slug composed of surfactant BA and ISPM demonstrated better profile control effect than the ISPM slug alone, and the enhanced oil recovery factor reached 15.65%.
研究领域:
石油工程
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材料科学
✓ 已验证
产品关联
DOI
高影响因子
POLYMERS FOR ADVANCED TECHNOLOGIES
·
2020
·Vol. 32
·期 1
·190-201
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IF 2.578
Jie He,Minglu Shao,Xiangan Yue,Tianqi Yue
In order to alleviate the contradiction between injectability of the profile control agent and its profile control performance, a novel core-shell heterogeneous structure colloidal particles (CSA) were synthesized, and the mechanism of self-aggregation plugging was proposed. Cross-linking inside the nanoparticles and chain-growth polymerization via capturing acrylamide in the aqueous phase result in the formation of core-shell heterogeneous structures as proved by TEM observation and XPS analysis. Moreover, CSA nanoparticles exhibit good hydrophilic properties, outstanding thermal stability and limited expansion capacity. Effects of different metal cations and surface group on the self-aggregation time of CSA nanoparticles were systematically studied. Results showed that divalent cations contributed to more significant aggregation of CSA nanoparticles in comparison to monovalent cations. The increasing cations concentration and valency decreased the thickness of electric double layer, which lead to a decrease in the zeta potential. Core flooding test shows that the injection of nanoparticles which diameter is much smaller that of pore-throats into the target reservoir can not only successfully enter the depth of porous media, but also effectively block the high permeability areas by the formation of self-aggregation particle clusters. This study provides a new method for the equilibrium between nanoparticles injectivity and in-depth profile control of nanoparticles.
研究领域:
石油工程
·
材料科学
✓ 已验证
产品关联
DOI
高影响因子
ACS Omega
·
2022
·
IF 4.132
Longlong Chen,Xinwei Liao,Shanfa Tang,Shuyun Feng,Ruijia Tang,Shaojing Jiang,Yuanwu Dong
Tight oil reservoirs have poor physical properties, insufficient formation energy, and low natural productivity. CO2 flooding is an important technical mean that enhances the oil recovery of dense reservoirs and achieves effective CO2 sequestration, but strong heterogeneity of the tight oil reservoir usually results in gas channeling and poor enhanced oil recovery effect. The existing methods to prevent gas channeling are mainly to use the small-molecule amine system and the polymer gel system to plug fracture and high permeability channels. The small-molecular amine system has low flash points and pollutes the environment and the polymer gel has poor injectivity and great damage to the formation, which limit their large-scale application. Therefore, a new viewpoint of CO2-low interfacial tension viscoelastic fluid synergistic flooding for enhanced oil recovery in a tight oil reservoir was made. The performance of low interfacial tension viscoelastic fluid (GOBT) was studied. The injectivity and oil displacement effect of CO2-GOBT synergistic flooding were evaluated, and the mechanism of CO2-GOBT synergistic flooding was discussed. The experimental results showed that 0.4% GOBT is a low interfacial tension viscoelastic fluid, which has strong adaptability to the salinity water of tight oil reservoirs (6788–80,000 mg/L), good viscosity stability at different pHs, excellent capacity to emulsify crude oil, and the ability to improve reservoir water wettability. CO2 alternating 0.4% GOBT flooding has good injection ability in cores (Ka = 0.249 mD), and injecting 0.4% GOBT can effectively increase the injection pressure of subsequent CO2 flooding. CO2 alternating 0.4% GOBT flooding can effectively improve water flooding recovery in tight sandstone reservoirs, which is better than CO2 flooding and 0.4% GOBT flooding in both homogeneous and heterogeneous conditions. The mechanisms of CO2 alternating 0.4% GOBT flooding to enhance the oil recovery include that GOBT and CO2 foam block high permeability layers, shunt and sweep low permeability layers, and GOBT emulsify and wash oil. CO2 partially dissolving in GOBT synergistically enhances the core water wettability, which improves GOBT injectability, emulsification, and stripping ability to residual oil.
研究领域:
石油工程
·
化学工程
✓ 已验证
产品关联
DOI
PubMed
高影响因子
Geoenergy Science and Engineering
·
2023
·
IF 0
Xu Li,Chunsheng Pu,Huilong Wei,Feifei Huang,Yun Bai,Chao Zhang
Polymer gels have been widely used in improving oil recovery and decreasing excessive water production in heterogeneous reservoirs after the long-term water flooding process. However, the high initial viscosity of polymer and the short gelation time still restricts the performance of polymer-based in situ cross-linked gels for in-depth conformance control. Herein, a novel gel system formed by in-situ crosslinking of water-soluble thixotropic polymer (WTP) and sustained-release crosslinker (SRC) was proposed. The WTP was synthesized by acrylamide, 2-acrylamido-2-methylpropanesulfonic acid, and N-[3-(dimethylamino)propyl] methacrylamide. It exhibits low viscosity under high shear rates and becomes thick under low shear rates, which ensures good injectability during the injection process and high gelation strength after cross-linking. The SRC was prepared by coating poly(ethyleneimine) (PEI) into the W/O/W multiple emulsions . The sustained-release mechanisms were well elaborated by confocal laser scanning microscopy (CLSM) observations. Only after the demulsification of multiple emulsions, the PEI would be released from the internal aqueous phase to the external aqueous phase. Therefore, these emulsions can be employed to deliver crosslinkers to specified targets in deep regions and prolong the release of crosslinkers to prevent undesirable crosslinking reactions near the injecting wells. According to the environmental scanning electron microscope (ESEM) observations and viscosity measurements, the low viscosity and an incompact spatial network could be observed in SRC/WTP gel system in the first 17 d, after which the PEI molecules were released to the external aqueous phase and cross-linked with WTP, forming the solid gel with small pores and yielding a high viscosity of 8793 mPa⋅s. Rheology tests have demonstrated that the elastic modules and the liner viscoelastic region of the novel gel system was nearly two times and twenty times than the traditional polymer gel, indicating higher gelation strength and better shear resistance. The core flooding tests showed that the SRC/WTP gel system had good injectability and could effectively plug the millimeter and submillimeter-sized cracks in low-permeability cores. 0.6 pore volume (PV) of SRC/WTP gel system with 3 gel slugs and a low injection rate can yield the best plugging performance in fractured core samples. And the gelation time shortens with the decrease of fracture apertures . Most importantly, the field tests in Ordos Basin verified the desirable EOR performance of the SRC/WTP gel system in fractured low-permeability reservoirs.
研究领域:
石油工程
·
化学工程
·
材料科学
✓ 已验证
DOI
危险品化学品经营许可证（带存储）