Volume 43,2026 Issue 2

• Synergistic Effect of Liquid Fibers and Resin Binder on Mechanical Properties of Cementing Slurry

  WANG Wei

  2026,43(2):191-197, DOI: 10.19346/j.cnki.1000-4092.2026.02.001

  Abstract: (1) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  Cement stone is a natural brittle material. If the cement sheath is broken，it will lead to sealing failure. In order to prevent the cement stone from being destroyed under the impact of external load，the carbon fiber mixture （1 mm carbon fiber and 0 . 7 mm carbon fiber at a mass ratio of 4 ∶ 1） that could be uniformly dispersed in cement slurry，was liquefied and dispersed to obtain liquid fiber with good dispersibility. Epoxy resin was modified to obtain resin emulsion that could improve flexibility and disperse stress. The synergistic effect of liquid fiber and resin emulsion on the mechanical properties of cement stone was studied in laboratory. The results showed that when the dosage of liquid fiber was 1 % and the dosage of resin emulsion was 3 %，the rheological property of the cement slurry was good，and the water loss was less than 40 mL，which could meet the thickening requirements of on-site construction. The mechanical properties of the formed cement stone were better than those of ordinary cement stone，and cement stone doped with single liquid fiber or single resin emulsion elastic-tough material. After 14 days of curing，the compressive strength of the cement stone was 43 . 2 MPa，the flexural strength was 14 . 1 MPa，and the impact strength reached up to 2 . 39 kJ/m² after 14 days of curing. Compared with common cement stone，the elastic limit strain was increased by 93 . 2 %，and the elastic modulus was decreased by 74 . 2 %，indicating that the elasticity of cement stone was improved obviously. The doped liquid fiber and resin emulsion had a good strengthening and toughening effect on cement stone，which ensured the long-term sealing performance of the cement sheath under external load environment and improved the impact resistance of cement stone.

• Preparation and Performance Characteristics of Acid - in - oil - in - water （A/O/W） Multiple Emulsified Acid

  CAO Guangsheng, QI Mingyu, XU Xuenan, ZHU Xinyu, SHI Dengqin, BAI Yujie

  2026,43(2):198-207, DOI: 10.19346/j.cnki.1000-4092.2026.02.002

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  Aiming at the problems of fast acid-rock reaction rate，short effective penetration distance and excessive dissolution near the wellbore in conventional acidizing of low-permeability carbonate reservoirs，in this paper，an acid-in-oil-in-water （A/O/W） multiple emulsified acid system was developed to achieve sustained-release and long-distance stimulation of reservoirs. The multiple emulsified acid system was constructed with white oil as the oil phase，compounded hydrochloric acid and acetic acid as the acid phase，Span 80 as the internal-phase emulsifier，and OP- 10 and water as the external aqueous phase，with emulsion stability adopted as the evaluation index. The formulation and preparation parameters were systematically optimized by investigating factors including oil-acid ratio，acid composition，type and concentration of emulsifiers，shear emulsification speed and emulsification time. Its sustained-release performance and acid stimulation effect were evaluated through high-temperature stability test，centrifugal stability test and core flooding experiment. The results indicated that the optimal formulation consisted of an oil-to-acid ratio of 5 ∶ 2，0 . 4 % Span 80 as the internal emulsifier，0 . 2 % OP- 10 as the external emulsifier，and a mixed acid solution containing 5 % hydrochloric acid and 5 % acetic acid. The optimal preparation conditions were a shear speed of 15 000 r/min and an emulsification time of 3 min. Under these conditions，the prepared multiple emulsified acid exhibited a uniform droplet-size distribution and an intact interfacial film，leading to the lowest acid separation ratio and the highest stability under both high-temperature and centrifugal conditions. Core flooding experiments showed that the system maintained a complete A/O/W structure with a pH value of approximately 6 in the near-wellbore zone （0 — 20 cm） . It gradually demulsified with the increase of injection distance and released a large amount of acid at a depth of 60 — 80 cm，realizing sustained release and effectively extending the action distance of acid. The A/O/W multiple emulsified acid prepared in this paper possesses both high stability and sustained-release characteristics，which can provide technical support for acidizing stimulation and production enhancement of low-permeability carbonate reservoirs.

• Plugging Performance and Adaptability of Water - soluble Urea - formaldehyde Gel in Fractured - vuggy Cells

  ZHAO Yuheng, QU Ming, SUN Haitong, WANG Jun, WU Weipeng, YANG Min, LIANG Tuo, HOU Jirui, ZHAO Yu

  2026,43(2):208-213, DOI: 10.19346/j.cnki.1000-4092.2026.02.003

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  To investigate the effectiveness of water-soluble urea-formaldehyde gel system in enhancing the remaining oil recovery during the late-stage waterflooding development of typical fractured-vuggy carbonate reservoirs in the Tahe oilfield，a macro-visualization physical model meeting similarity criteria was designed and constructed. Based on this model，a comparative study was conducted to evaluate the plugging performance of the gel and its effect on remaining oil recovery in three types of fractured-vuggy cells. The results showed that the water-soluble urea-formaldehyde gel system exhibited good injectivity under the conditions of 150 ℃ and 252 903 mg/L salinity. In sediment-filled models，the gel mainly accumulated along cavity walls，while in collapse-filled and loose fill models，it distributed continuously and uniformly. The gel could induce flexible fluid diversion in the reservoir，and achieved effective cementation and plugging of internal reservoir media and fracture channels. Furthermore，after conventional waterflooding，injection of the water-soluble urea-formaldehyde gel system increased recovery factors by 18 . 61，18 . 13，and 13 . 64 percentage points in sediment-filled，collapse-filled and loose fill models，respectively，and maintained plugging efficiency exceeding 98 % in all three model types. This research confirmed that the water-soluble urea-formaldehyde gel system delivered excellent plugging performance and enhanced oil recovery across different fractured-vuggy structures with broad adaptability，which conld provide reliable technical support for field applications of this technology.

• Distribution and Migration Depth of Weak Gel under Heterogeneous Condition

  XUE Xinfang, YANG Jinzhou, WANG Yefei, LI Xiang, QIU Shize, XU Guorui, ZHANG Junqian, YU Tong, DING Mingchen

  2026,43(2):214-220, DOI: 10.19346/j.cnki.1000-4092.2026.02.004

  Abstract: (3) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  The distribution and migration ability of weak gel directly affect its profile control and flooding performance. Conventional plugging experiments using core models cannot intuitively observe gel distribution，and rarely reflect the influence of reservoir heterogeneity on migration process. In this paper，weak gel profile control and flooding as well as CT scanning experiments were carried out in long sand filling model，large-size visual heterogeneous model and heterogeneous core model，respectively，to systematically study the spatial distribution and migration depth of weak gel. The results of long sand filling model showed that before reaching final setting time （12 . 0 — 14 . 0 h），the dynamic injection pressure of the gelling fluid had increased significantly to a maximum of 37 . 5 MPa. On the one hand，this confirmed the occurrence of dynamic gelation；on the other hand，it indicated that the migration resistance of gelling fluid increased sharply and flow became difficult before final setting in porous media，so final setting time could not accurately reflect the fluidity of gelling fluid in porous media. During gelling fluid injection and subsequent water flooding，weak gel could migrate，but the migration distance was very limited. The total length of the model was 21 . 5 m；weak gel only was squeezed to 0 — 4 . 2 m section in the gelling stage，and subsequent water flooding could only push it to 4 . 2 — 8 . 5 m section for plugging requiring an extremely high displacement pressure of 15 . 0 — 37 . 5 MPa. The results of visual heterogeneous model showed that the plugging depth of the first round of weak gel was about 27 . 0 cm. During subsequent water injection and the injection of the second and third rounds of gelling fluid，the injected fluid had obvious bypass flow，the injection pressure only increased slightly，the gel of previous rounds did not migrate significantly，and it would also block the migration of subsequent rounds of gelling fluid. After three rounds of injection，the total plugging depth was only 43 . 3 cm，which was far less than the total length of the model （200 . 0 cm），confirming that weak gel had very poor migration ability or even basically could not migrate under heterogeneous conditions. The fluid distribution results of heterogeneous core model further verified that weak gel could basically not achieve effective deep migration after gelation under heterogeneous conditions，and it played more role of “ profile control ” rather than “ profile control and flooding ” .

• Profile Control Performance and Mechanism of Multi - component Emulsion System in Heavy Oil Reservoir

  GONG Yuning, HE Houfeng, ZHENG Haoran, SHANG Ce, FENG Tian, GAO Fei, DING Mengfan

  2026,43(2):221-231, DOI: 10.19346/j.cnki.1000-4092.2026.02.005

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  In order to enhance oil recovery of heavy oil reservoirs，in this paper，the profile control performance of binary （surfactant-nanoparticle） and ternary （surfactant-nanoparticle-polymer） synergistically stabilized emulsions at different oil-water ratios on high and low permeability cores was systematically investigated by using heterogeneous dual-core parallel experiments combined with CT scanning. The results showed that the O/W emulsion stabilized by the ternary system achieved the optimal profile control effect when the oil-water ratio was 1 ∶ 9 . After injecting 0 . 13 PV of emulsion，the diversion rate of the high-permeability core stabilized at approximately 55 %，and the diversion rates of the high- and low-permeability cores could quickly reach and maintain equilibrium，realizing effective and durable mobility control. With continuous emulsion injection，the displacement pressure difference of all systems gradually increased and reached a peak at the injection volume of 0 . 5 PV . The peak pressure difference increased significantly with the rise of oil-water ratio，the peak pressure difference corresponding to oil-water ratios of 1 ∶ 9，3 ∶ 7，and 5 ∶ 5 was 1 . 6，4 . 2，and 8 . 2 MPa，respectively. When the emulsion with oil-water ratio of 5 ∶ 5 was injected，no demulsification occurred，and a large number of oil droplets were retained in the pores. When injecting emulsions with oil-water ratios of 1 ∶ 9 and 3 ∶ 7，the volume fraction of oil phase in the produced fluid was higher，which reflected the plugging effect of polymers：polymers could significantly increase displacement pressure while endowing the system with strong fluidity，promoting crude oil to be produced in the form of O/W emulsion. In addition，the addition of polymer reduced emulsion droplet size and decreased the proportion of large droplets that played a major role in plugging. Therefore，at the oil-water ratio of 1 ∶ 9，the plugging performance of the ternary system emulsion was slightly lower than that of the binary system. The matching between emulsion droplet size and pore throat scale was the key factor affecting plugging efficiency. The ternary system emulsion had concentrated particle size distribution and stronger matching with the pore throat of main flow channels，making it easier to form a stable plugging structure in pore throats. This study provides theoretical basis and technical support for efficiency improvement of cold production and optimization of later development of heavy oil reservoirs.

• Preparation and Performance of In - situ Self - aggregating Nano - profile Control Agent for Low - permeability Reservoirs

  HE Jie, LUO Min, WANG Wei, ZHU Jiajie, ZHENG Lijun, FAN Haibo

  2026,43(2):232-239, DOI: 10.19346/j.cnki.1000-4092.2026.02.006

  Abstract: (3) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  To address the limitations of conventional polyacrylamide microsphere profile control agents used in low-permeability reservoirs，including poor temperature and salt resistance，and the prominent contradiction between water-absorbing swelling capacity and plugging performance，this study prepared an in-situ self-aggregating nano-profile control agent （In-situ SNP） via emulsion polymerization，using methyl methacrylate and styrene as main raw materials，and N -hydroxymethylacrylamide as the functional monomer. The chemical structure and micromorphology of In-situ SNP were characterized by Fourier transform infrared spectroscopy （FTIR） and transmission electron microscopy （TEM） . Its water-absorbing swelling capacity，salt tolerance，temperature resistance and in-situ self-aggregation behavior were systematically investigated. Furthermore，its injectivity，deep migration performance and profile improvement capacity were evaluated through core flooding experiments. Characterization results revealed that In-situ SNP consisted of spherical particles with a core-shell structure and an average diameter of 60 nm. Performance studies demonstrated its weak water absorption and swelling properties，exhibiting a swelling ratio of only 67 . 18 % even in deionized water at 90 ℃ . It also showed excellent salt and temperature tolerance，dispersing uniformly in brine with Na⁺，Mg²⁺，and Ca²⁺ concentrations of 25 . 0 ×10⁴，5 . 0 ×10⁴，and 5 . 0 ×10⁴ mg/L，respectively. After being aged for 180 days in formation water at 110 ℃，the mass retention rate remained as high as 95 . 66 %. In-situ SNP exhibited favorable injectivity，enabling smooth migration into the deep zones of low-permeability reservoirs. Through condensation reactions between the — CH₂ OH groups in its molecular structure，the agent underwent in-situ self-aggregation to form large-sized aggregates，effectively blocking dominant flow channels and significantly improving the water injection profile. For low-permeability parallel cores with permeability contrasts ranging from 20 . 1 to 40 . 9，the injection of In-situ SNP achieved a profile improvement rate of 86 . 4 % to 91 . 3 %.

• Preparation and Performance Evaluation of Pre - assembled Core - shell Phase - transition Profile Control Agent for Fractured Low - permeability Reservoirs

  WANG Qianlong, ZHU Jiajie, ZHENG Lijun, ZHANG Ning, HUANG Hai

  2026,43(2):240-248, DOI: 10.19346/j.cnki.1000-4092.2026.02.007

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  The Chang 6 fractured low-permeability reservoir of the Wuqi W block is characterized by highly developed microfractures，limited waterflood sweep efficiency，and the formation of dominant flow channels during long-term water injection，which make conventional plugging agents ineffective for deep profile control. Based on the above issues，a pre-assembled core-shell phase-change profile control agent （TSAD） was developed using a multi-component modified epoxy resin system as the core and a biopolysaccharide as the outer shell，enabling deep migration and temperature-induced phase-transition solidification to meet the requirements of deep profile control in fractured low-permeability reservoirs. Dynamic light scattering，rotational viscometry，microfracture piston extrusion，and core flooding experiments were employed to systematically investigate the particle size distribution，phase-transition characteristics，plugging strength，water-plugging and oil-displacement performance of TSAD. The results showed that TSAD exhibited a particle size distribution of 20 — 300 nm after phase transition，indicating excellent injectivity；the phase-transition time could be adjusted within 5 — 12 days，which could meet the requirements of deep profile control. The plugging strength increased with the increase of injection mass fraction. TSAD achieved a breakthrough pressure of 8 . 56 MPa and a stable pressure of 8 . 02 MPa at 2 . 5 % mass fraction，meeting the strength requirements for deep plugging. The phase-transition behavior was not affected by the pH or salinity of field formation water. Core flooding tests demonstrated a plugging rate of 80 . 69 % in high-permeability cores and only 3 . 1 % in low-permeability cores under injection of 0 . 3 PV 1 . 0 % TSAD，with the oil displacement efficiency in low-permeability core improved by 13 . 44 percentage points，confirming its capability to effectively block dominant channels of fractures and enhance oil recovery. A field pilot test was conducted in the X-XX well group of the Chang 6 reservoir in the Wuqi W block. The water cut decreased by 25 . 85 %，and the daily oil production increased from 5 . 84 t to 7 . 33 t，achieving an incremental oil production of 1 . 49 t/d. These results demonstrate that TSAD provides excellent deep-profile control performance in fractured low-permeability reservoirs，offering a new and effective technical approach for water control and enhanced oil recovery.

• Switchable Active Nanofluids for Achieving Heavy Oil Viscosity Reduction via Emulsification

  LI Xiaoliang, CHEN Bin, WU Xiaoyan, ZHANG Huiqing, MENG Fantao

  2026,43(2):249-257, DOI: 10.19346/j.cnki.1000-4092.2026.02.008

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  The recovery of heavy oil is challenging due to its high viscosity and low mobility. Emulsifying heavy oil into stable heavy oil-in-water emulsions is an effective strategy to improve heavy oil mobility and enhance oil recovery. However，on space-constrained offshore platforms，these emulsions must be rapidly demulsified after production，so the development of stimuli-responsive demulsification technology has become a research priority. In this study，a responsive EO-PO type pseudo-gemini surfactant，di （C_18:1E₅） -P_2-3，was synthesized via an acid-base neutralization reaction and subsequently compounded with SiO₂ nanoparticles to formulate a switchable active nanofluid. The thermal and salinity tolerance of di （C_18:1E₅） -P_2-3，alongside the emulsification viscosity reduction performance of the active nanofluid for heavy oil，were systematically investigated. Furthermore，the interfacial stabilization mechanism and the stimuli-responsive demulsification performance of the heavy oil emulsion were thoroughly explored. The results demonstrated that the surfactant exhibited excellent thermal and salt tolerance，making it suitable for high-temperature and high-salinity reservoirs. The active nanofluid，formulated by combining the surfactant with nano-SiO₂，efficiently stabilized heavy oil-in-water emulsions，achieving a water separation rate as low as 5 . 5 % after 30 minutes of standing and a viscosity reduction rate exceeding 95 %. The exceptional emulsion stability stemmed from the synergistic adsorption of di （C_18:1E₅） -P_2-3，SiO₂ nanoparticles，and asphaltenes at the oil-water interface，which collectively formed a dense interfacial film that effectively inhibited droplet coalescence. More importantly，the heavy oil emulsion exhibited excellent stimuli-responsive demulsification performance. Upon bubbling CO₂，the pseudo-gemini surfactant dissociated，resulting in a water separation rate approaching 100 % within only 5 minutes of standing. This work enables simultaneous achievement of enhanced heavy oil recovery via subsurface emulsification and rapid demulsification of produced emulsions，providing an innovative and feasible technical pathway for the green and intelligent development of offshore heavy oil.

• Reservoir Adaptability and Improvement Measures of Reinjected Sewage in Ultra - high Water Cut Oilfield

  MENG Xinzhi, CAO Weijia, LU Xiangguo, LIU Zilong, XIE Kun, WANG Yongjiang, YIN Xianpei, ZHANG Zhijun

  2026,43(2):258-264, DOI: 10.19346/j.cnki.1000-4092.2026.02.009

  Abstract: (3) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  At present，the main oilfields in eastern China are in the ultra-high water cut development stage，and the inefficient and ineffective circulation is very serious. The treatment of a large amount of produced fluid leads to a sharp increase in production and operation costs. The main technical indicators of reinjected sewage are often difficult to meet industrial requirements. Residual polymers，crude oil and suspended solid particles in the sewage are bound to cause plugging damage to low-permeability zones of the reservoir. In order to clarify the permeability limit of reservoirs for sewage reinjection and establish methods to improve the reservoir adaptability of sewage，the reinjected sewage and reservoir physical properties of XSG Oilfield were taken as research objects，and an experimental study on reservoir adaptability and improvement measures of reinjected wastewater in ultra-high water cut oilfields was conducted. The results showed that the oil content，suspended solid content and median particle size of reinjected sewage from the three under-injection wells far exceeded the industrial water quality standards. Retention and plugging of these substances in the pores of reservoir cores were the main causes of water well under-injection. The minimum permeability of the reinjection reservoir for sewage from Well 1 # was about 169 × 10^-3 μm²，and that for Well 3 # was about 103 × 10^-3 μm² . A n o p t i m a l blending ratio of sewage to fresh water could increase the Zeta potential of suspended particles in the blended water，enhance the stability of suspended particles，improve the compatibility between suspended particle size and core pores，and reduce the degree of plugging damage to t he reservoir. From a techno-economic perspective，the reco mmended wastewater-to-fresh water ratios were 4 ∶ 6 for Well 1 # and 6 ∶ 4 for Well 3 #.

• CO₂ Huff - n - Puff Seepage Patterns and Distribution Characteristics of Remaining Oil in Different Fracture Zones under Influence of Water Invasion Layers in Tight Reservoirs

  XIE Shengchen, HUANG Shijun, ZHAO Fenglan, YANG Mingyang, TAO Danfeng

  2026,43(2):265-273, DOI: 10.19346/j.cnki.1000-4092.2026.02.010

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  After volumetric fracturing of horizontal wells in tight reservoirs，water from the fracturing fluid seeps into the reservoir and forms a “ water invasion layer ” in the near-well area，which affects the development effect of CO₂ huff- n -puff. To clarify the influence of the water invasion layer on the swept range of CO₂ huff- n -puff，core physical simulation combined with low-field nuclear magnetic resonance imaging was adopted to analyze the remaining oil distribution characteristics and T₂ spectra of CO₂ huff- n -puff at different cycles. The effect of water invasion layer，as well as the coexistence of water invasion layer and fractures on CO₂ huff- n -puff performance was investigated，and the corresponding seepage mechanism was analyzed. The results showed that in non-fractured zones，the existence of water invasion layer weakened the gravity override of CO₂ huff- n -puff，formed an arc-shaped huff- n -puff front with smaller curvature，and reduced the swept range and recovery degree of CO₂ huff- n -puff. In fractured zones，the water invasion layer changed the huff- n -puff front from elliptical to "U" shape，and also reduced the swept range and recovery degree of CO₂ huff- n -puff，but both indicators were higher than those in non-fractured zones. The water invasion layer affected the performance and swept range of CO₂ huff- n -puff by hindering the contact between CO₂ and crude oil and changing the flow velocity distribution of CO₂ in the seepage area. Regardless of whether fractures existed or not，when the water invasion layer hindered the contact between CO₂ and crude oil，CO₂ always tended to break through the water invasion layer at the position with the largest local pressure gradient，the highest flow velocity，where capillary resistance was overcome first. The research results clarified the remaining oil distribution characteristics and seepage mechanism of CO₂ huff- n -puff in tight reservoirs under the influence of water invasion layer，which provided certain reference for CO₂ huff- n -puff development in similar reservoirs.

• Preparation and Performance Evaluation of Modified Nano - graphene Oxide Asphaltene Inhibitor

  LIU Li, ZHAO Shuaishuai, LIU Jinxin, XIAO Chuanmin, LI Zhihao, XING Mengyi

  2026,43(2):274-282, DOI: 10.19346/j.cnki.1000-4092.2026.02.011

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  To address the issues of reservoir pore-throat blockage and permeability decline caused by asphaltene deposition during CO₂ flooding in low-permeability reservoirs，this study proposes a novel technical approach utilizing nanomaterials to inhibit asphaltene deposition. Using graphene oxide （GO），aniline，and decylamine as raw materials，modified nano-graphene oxide （GO-BD） was prepared via covalent grafting. Systematic asphaltene dispersion experiments and online CO₂ flooding experiments based on low-field nuclear magnetic resonance （NMR） were conducted to evaluate its effectiveness in inhibiting asphaltene deposition. The research results showed that the GO-BD obtained via GO modification exhibited good hydrophobicity. GO-BD had excellent performance in inhibiting asphaltene deposition，which could significantly delay the onset of asphaltene precipitation and reduce the size of asphaltene aggregates. At a GO-BD mass concentration of 25 mg/L，the asphaltene precipitation point of the oil sample increased from 42 . 03 % to 58 . 27 %，and the particle size of asphaltene aggregates decreased from 1297 nm to 537 nm. During CO₂ flooding，compared with pure CO₂ injection，the addition of 0 . 8 % mass fraction of GO-BD inhibitor to crude oil reduced core permeability damage rate by 20 . 8 %，decreased pore blockage rate by 7 % — 10 %，and enhanced oil recovery by more than 10 percentage points. This research provides reference and guidance for the application of nanofluid materials to inhibit asphaltene deposition during CO₂ flooding.

• Experimental Study on Identification and Micro Control of Damage Mechanism in Shale Oil CO₂ Flooding Reservoir

  WANG Ruyi, QU Shiyuan, LI Huili, HUANG Bo, WANG Siqi, ZU Kai, YE Zhilin

  2026,43(2):283-290, DOI: 10.19346/j.cnki.1000-4092.2026.02.012

  Abstract: (3) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  In order to explore the reservoir damage characteristics of shale oil CO₂ flooding，based on the natural core and shale oil samples of a shale oil reservoir in the west，the shale oil reservoir damage caused by gas channeling，asphaltene deposition and Jamin effect was studied through laboratory experiments. Through permeability change analysis，nuclear magnetic resonance response and contact angle test，the intervention effects of various micro-regulation methods on typical damage mechanisms were explored. The results showed that gas channeling made gas breakthrough in high permeability layer，which led to the decrease of overall recovery rate during commingled production. The influence of asphaltene deposition on low permeability cores was more obvious，mainly concentrated on the injection side. The Jamin effect led to a decrease in permeability when the downstream back pressure was lower than the miscible pressure. The high permeability core was less affected，while the low permeability core was greatly affected and was not easy to be relieved. The measures and suggestions for reducing reservoir damage such as gas-water alternation，anti-deposition of gas injection wells，and change of production pressure difference were given，which provided theoretical support and technical guidance for the efficient development of shale oil by CO₂ flooding.

• Synthesis and Performance Evaluation of Amide Sulfonate Zwitterionic Surfactants

  ZHANG Xiangchun, ZHANG Zheng, WU Ke, YAN Qiangwei, YUAN Bin, JIANG Xuanxuan

  2026,43(2):291-296, DOI: 10.19346/j.cnki.1000-4092.2026.02.013

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  To address the limitations of traditional zwitterionic surfactants in terms of insufficient interfacial activity and tolerance under harsh conditions，a novel amide sulfonate zwitterionic surfactant （LECN） was synthesized via a two-step reaction using lauric acid （LA），N，N -dimethylethylenediamine （DMEDA），and sodium 3 -chloro- 2 -hydroxypropanesulfonate （CHPS-Na） as raw materials. The optimal molar ratio of LA，DMEDA，CHPS-Na was determined to be 1 ∶ 1 . 1 ∶ 1 . 1 . The comprehensive performance of LECN，including surface/interfacial activity，foam properties，emulsifying stability，and temperature and salt resistance，was systematically evaluated. The results showed that LECN exhibited a critical micelle concentration of 0 . 05 g/L，with a corresponding surface tension of 28 . 2 mN/m. At the mass concentration of 0 . 1 g/L，LECN could reduce the interfacial tension between cyclohexane and water to 0 . 045 mN/m. At 25 ℃，the 0 . 05 g/L LECN system achieved a foam volume of 670 mL and a half-life of 1900 s. The 0 . 05 g/L LECN system showed good emulsifying stability with a water separation rate of only 35 . 5 % after 70 minutes. Moreover，under 120 ℃ and a salinity of 120 g/L，the variation in surface tension was ≤ 4 . 7 mN/m，demonstrating excellent temperature and salt resistance. All these properties were significantly superior to those of the reference samples CAB，SDS，and Triton X- 100 . The synthesis of LECN features readily available raw materials，mild reaction conditions，and simple operation，showing great potential for industrial application. This work provides a new strategy for the development of high-performance zwitterionic surfactants and is expected to promote their application in petroleum extraction，daily chemicals and other fields.

• Shear Viscosity Recovery Performance of Ultrahigh Molecular Weight Zwitterionic Polymer Aqueous Solution

  YANG Haien, ZENG Lixiang, SONG Mingming, LIU Yunlong, FENG Xiaoya, LIU Yan, WU Baoqiang, CAO Lu, SHI Mengquan

  2026,43(2):297-305, DOI: 10.19346/j.cnki.1000-4092.2026.02.014

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  To address the problem of shear viscosity loss of polymers in porous media of low-permeability reservoirs，an ultra-high molecular weight zwitterionic polymer （HSC） with viscosity-average molecular weight of 21 . 38 million was prepared via copolymerization of acrylamide （AM），2 -acrylamide- 2 -methylpropanesulfonic acid （AMPS），dimethyl diallyl ammonium chloride （DMDAAC） and a small amount of acrylic acid （AA），followed by post-hydrolysis. Cationic and anionic zwitterionic groups were simultaneously introduced onto the polymer chains. The molecular structure of the target quaternary polymer was characterized by FT-IR and ¹H-NMR. The factors affecting shear viscosity recovery performance were investigated from the aspects of polymer composition and injection rate using a self-built constant-flow capillary shear device，and the viscosity recovery process of the sheared polymer was analyzed by DLS，TEM and rheological characterization. The results showed that the reversible attractive interaction between cationic and anionic groups enhanced the initial viscosity of the polymer and endowed it with viscoelastic properties. After shear thinning in capillary，the ionic bonds between polymer chains could be reestablished spontaneously to reconstruct the associated network，enabling rapid viscosity recovery. The polymer prepared with 20 % AMPS，0 . 02 % ammonium formate，0 . 5 % DMDAAC and 25 % hydrolysis degree exhibited the optimal shear viscosity recovery performance. Under a shear rate of 4500 s^-1，its viscosity could recover to more than 80 % of the initial value within 1 hour. The excellent shear viscosity self-healing property and resistance to formation adsorption endow HSC with great application potential in deep profile control and flooding for low-permeability reservoirs.

• Oil - displacing Capacity and Corrosion Inhibition Behavior of Bacillus V elezensis

  XIE Juan, YANG Wen, GUO Ge, CHEN Ying, LI Jiangang

  2026,43(2):306-312, DOI: 10.19346/j.cnki.1000-4092.2026.02.015

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  In view of the aggravation of steel corrosion in microbial enhanced oil recovery （MEOR） technology，Bacillus velezensis 4 - 19 was isolated from the produced water of Changqing oilfield. The oil displacement efficiency of the strain and the synergistic mechanism of the strain on the corrosion inhibition of J 55 steel were investigated. The degradation of heavy components was characterized by crude oil viscosity reduction experiment，four-component analysis and meteorological chromatography analysis. The corrosion inhibition behavior was analyzed by weight loss method，electrochemical impedance spectroscopy （EIS） and scanning electron microscopy （SEM） . The protective mechanism of the film was revealed by combining equivalent circuit fitting and X-ray energy spectrum （EDS） . The results showed that 4 - 19 could reduce the surface tension of crude oil by 54 . 5 % and the viscosity of crude oil decreased to some degree，after the action of strain 4 - 19 for 3 days. The content of saturated hydrocarbons in crude oil increased from 49 . 5 % to 58 . 4 %，the content of aromatic hydrocarbons and resins decreased from 17 . 6 % and 27 . 4 % to 14 . 5 % and 22 . 3 %，respectively，and the content of asphaltene decreased from 5 . 5 % to 4 . 8 % . The corrosion rate of the J 55 steel decreased by 75 . 1 % . EIS analysis showed that the film resistance （R_b） increased by 42 . 6 % and the polarization current density decreased by 76 . 7 % . By secreting lipopeptide biosurfactants to degrade heavy components and competitively consume oxygen，4 - 19 formed a dense corrosion product film to realize the coupling of oil displacement and corrosion inhibition function，which provided a new strategy for MEOR field application.

• Influence of Composition of Polymer Flooding Water Transition Layer on Electrical Dehydration Behavior and Demulsification Effect

  HAN Zhaokang, WEI Lixin, GAO Qinghe, LI Limin, QIAN Huijuan, HU Jinmei

  2026,43(2):313-322, DOI: 10.19346/j.cnki.1000-4092.2026.02.016

  Abstract: (1) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  To address the issue of the stable oil-water "transition layer" in polymer flooding produced fluid，which is formed by the synergistic effects of resins，asphaltenes，mechanical impurities，and polymers，the composition of the transition layer was analyzed and the inhibition mechanism of its main components on the electric dehydration process was revealed. A synergistic treatment scheme combining an electric field and chemical agents was proposed，and its electro-chemical synergistic destabilization mechanism was demonstrated. The results indicated that the SYP- 416 with a mass concentration of 500 mg/L had a significant effect on treating the "electric field collapse" phenomenon caused by solid phase，reducing the water content in the oil to 1 . 36 % after 1 hour of electric desalination. The SYP- 417 with a mass concentration of 500 mg/L had a relatively obvious effect on treating the "electric field collapse" phenomenon caused by oil phase，reducing the water content in the oil to 2 . 31 % after 1 hour of electric desalination；while the compound agent （mass ratio of SYP- 416 to SYP- 417 being of 1 ∶ 1） with a concentration of 500 mg/L had a remarkable effect on treating The oil sample of the transition layer on site，reducing the water content in the oil to 0 . 96 % after 1 hour of electric desalination. The compound agent could effectively address the issue of "electric field collapse" in the electric dehydrator caused by the transition layer. The current had significantly decreased，and the synergistic mechanism between the chemical agent and the electric field had significantly enhanced the mass transfer efficiency of interface water molecules and solid particles，achieving efficient demulsification and separation. The field application results confirm that the technology can restore the operation stability of the electric dehydrator.

• Green Synthesis of Magnetic Nanoparticles Fe₃O₄ NPs and Their Application in Oil Removal from Oily Wastewater

  LI Landuo, ZHANG Cenqian, GAO Jie, FU Jian, HAN Yuxiao, WANG Bo, DENG Shuyuan, SHE Yuehui

  2026,43(2):323-329, DOI: 10.19346/j.cnki.1000-4092.2026.02.017

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  In order to develop an efficient adsorbent suitable for water body remediation，magnetic nanoparticles （Fe₃O₄ NPs） were prepared by green synthesis method using low-cost and easily-obtained Inonotus oblquus extract，and applied to the oil removal treatment of oily wastewater. This study aimed to cope with the challenges of high cost，complex process and low bioavailability in the preparation of traditional nanomaterials. The synthesized magnetic nanoparticles Fe₃O₄ NPs were systematically analyzed by Fourier transform infrared spectroscopy （FT-IR），scanning electron microscopy （SEM），transmission electron microscopy （TEM） and other characterization methods. The results showed that the bioactive substances in inonotus obliquus extract participated in the synthesis of Fe₃O₄ NPs as both reducing agent and stabilizer. The prepared Fe₃O₄ NPs were irregularly spherical，with an average particle size of 16 . 69 nm，a Zeta potential of - 31 . 7 mV，exhibiting good stability. The saturation magnetization of Fe₃O₄ NPs was 30 . 2 A · m²/kg. The magnetization curve showed that the material had superparamagnetism and was easy to be separated and recovered. The optimum conditions for oil removal by Fe₃O₄ NPs were as follows：concentration 500 mg/L，temperature 50 ℃，treatment time 30 min and stirring speed 200 r/min. The oil removal rate reached 90 . 24 %，demonstrating excellent oil removal performance. This study ingeniously integrates the advantages of nanotechnology，biotechnology，and green chemistry，providing a new approach for the green treatment of oily wastewater.

• Effect of Complex Media in Oil Fields on Performance of Scale Inhibitors

  FENG Keting, YUAN Huiying, YANG Le, WANG Yisha, CHEN Bin, TIAN Yuxin, LYU Feng

  2026,43(2):330-336, DOI: 10.19346/j.cnki.1000-4092.2026.02.018

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  In the process of oilfield development and production，scale inhibitors are widely used to mitigate scaling in reservoirs，wellbores，and transportation pipelines. However，the interaction mechanism between scale inhibitors and scaling ions such as Ca²⁺ and Mg²⁺ in high-salinity fluids remains unclear，and the coupling effects among field-applied scale inhibitors，biocides and corrosion inhibitors have not been systematically investigated，which hinders the efficient and scientific application of chemical agents. In this study，a dynamic testing platform based on laser turbidity was innovatively established，which enabled rapid batch testing of scale inhibitor performance under simulated reservoir conditions including oxygen-free environment，high temperature and flowing state. The effects of Mg²⁺，Fe²⁺ and Sr²⁺ on the scaling of CaCO₃ and BaSO₄ were investigated respectively，and the interaction between commonly used oilfield additives and scale inhibitors was analyzed. The results showed that the presence of Mg²⁺，Fe²⁺ and Sr²⁺ could prolong the induction time of CaCO₃ and BaSO₄ scaling respectively，and improve the scale inhibition efficiency. The introduction of multiple ions promoted the formation of Ba_xSr_1-xSO₄，Ca_xMg_1-xCO₃ and Ca_xFe_1-xCO₃ solid solution mixed scales，reduced the surface energy of scale crystals，and slowed down the scaling rate. Scale inhibitors exhibited synergistic effect with oilfield demulsifiers and corrosion inhibitors，while showing antagonistic effects with biocides. These findings provide guidance for the precise screening of high-efficiency synergistic chemical systems and the cost reduction and efficiency improvement of chemical anti-scaling technologies.

• Synthesis of Quaternized Triazole Corrosion Inhibitor and its Corrosion Inhibition behavior on N 80 Steel

  WEI Yongzhou

  2026,43(2):337-346, DOI: 10.19346/j.cnki.1000-4092.2026.02.019

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  To address the insufficient electrostatic adsorption capacity of traditional triazole corrosion inhibitors in strong acid environments，this study proposes a “ dual-active-center ” molecular design strategy. A novel quaternized inhibitor，Q 3 -A T，was synthesized via the nucleophilic ring-opening reaction between 3 -amino- 1 , 2 , 4 -triazole and 2 , 3 -epoxypropyltrimethylammonium chloride，and its structure was confirmed by FT-IR and ¹H-NMR. The corrosion inhibition performance and adsorption behavior of Q 3 -A T on N 80 steel in 1 mol/L HCl solution were systematically investigated using weight loss measurement，electrochemical techniques （EIS and potentiodynamic polarization），and surface analysis methods （SEM/AFM/XPS/contact angle measurement） . The results showed that Q 3 -A T acted as an excellent mixed-type inhibitor，and the inhibition efficiency reached 96 . 34 % at the concentration of 500 mg/L. Thermodynamic analysis indicated that the adsorption of Q 3 -A T on N 80 steel surface conformed to the Langmuir monolayer adsorption model，and it was a spontaneous mixed physisorption-chemisorption process. Surface morphology analysis confirmed that the addition of Q 3 -A T significantly reduced the surface roughness of the substrate （from 160 nm to 106 nm） and improved surface hydrophobicity. The detection of N — Fe coordination bonds by XPS further verified the existence of chemisorption. A synergistic “ electrostatic anchor-coordination claw ” corrosion inhibition mechanism was proposed：Q 3 -A T rapidly pre-adsorbed onto the negatively charged interface using quaternary ammonium cations as “ electrostatic anchors ”，and then formed stable chemical bonds with iron using triazole rings as “ coordination claws ” . This work provides a novel molecular design strategy for developing high-efficiency corrosion inhibitors for oil and gas acidizing operations.

• Separation and Detection of Oil - soluble Tracers for Oilfield Application Based on Gas Chromatography Technology

  LI Yang, LI Jianrong, LI Rongqiang, LUO Shuifa, GAO Xiaoming, LI Kexing, WU Jundao, ZAIROV Rustem, BEBY AKINA Anastasiya, YUAN Chengdong

  2026,43(2):347-351, DOI: 10.19346/j.cnki.1000-4092.2026.02.020

  Abstract: (1) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  The complexity of fluid flow during reservoir development often renders conventional water injection or stimulation measures ineffective. Traditional water-soluble tracers used for monitoring water injection fronts have significant limitations in revealing the remaining oil distribution and oil phase flow behavior. To address these limitations，this study aimed to establish a rapid method for the separation and detection of oil-soluble tracers in crude oil based on gas chromatography （GC） technology. Through solvent screening experiments，methanol was selected as the optimal extractant due to its minimal extraction of crude oil components and low signal interference. To tackle the issues of water interfering with extraction efficiency and residual heavy components prolonging the analysis cycle，an optimized sample pretreatment process was proposed. This involved in adding isooctane （20 % mass fraction） and excess K₂CO₃ to the tracer-containing crude oil. After dehydration via stirring，ultrasonic treatment，and centrifugation，the methanol extract was frozen at - 32 ℃ to remove impurities before analysis by the gas chromatograph. Experimental results demonstrated that the pretreatment method effectively removed water and significantly reduced interference from heavy oil components. The precise separation and identification of signal peaks for 38 oil-soluble tracers could be achieved within 10 hours using a single injection. The method is rapid and efficient，meeting the requirements for field monitoring of oil phase flow and reservoir characterization.

• Testing Method for Content of Cross - linked Network Structure of Viscoelastic Particle Oil Displacement Agent

  PAN Binlin, CHEN Xiaoyan, LIU Yu, JIANG Zuming, SONG Xinyue, SHI Jing

  2026,43(2):352-357, DOI: 10.19346/j.cnki.1000-4092.2026.02.021

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  Viscoelastic particle oil displacement agents （including PPG and B-PPG） have both partially cross-linked structure and partially branched molecular structure. The content of cross-linked network structure greatly influences their oil displacement performance，and is a core characteristic parameter for evaluating the performance of this type of oil displacement agent. However，there is still a lack of effective characterization methods for the cross-linked network structure content of PPG and B-PPG products. In this paper，a quantitative detection method based on complexant chelation combined with liquid chromatography was established to determine the cross-linked network structure content of PPG and B-PPG. First，the gel particles in PPG and B-PPG dispersions were fully crushed，then aluminum nitrate was used as complexant to chelate and eliminate the interference of linear structure in the system. Combined with liquid chromatography detection of the change of polymer peak area during the chelation process，it was confirmed that the chelation process presented a three-stage characteristic with the increase of aluminum nitrate dosage. After the completion of the first stage，the ratio of the minimum polymer chromatographic peak area to the original peak area was the cross-linked network structure content of PPG and B-PPG. The established method was applied to test actual viscoelastic particle oil displacement agent samples，the results showed that the cross-linked network structure content of B-PPG was about 86 %，and that of PPG was about 25 %，the proportion of cross-linked network structure in B-PPG was significantly higher than that in PPG. This method can achieve accurate quantification of the cross-linked network structure content of viscoelastic particle oil displacement agent，and provide an important technical means for performance optimization and quality control of this type of oil displacement agent.

• Advances on Emulsion Stabilization and Phase Inversion Technology for Water Shutoff in Oilfield

  SHEN Linghong, LU Yuanyuan, KANG Bohan, YANG Yuqi, YIN Taiheng

  2026,43(2):358-369, DOI: 10.19346/j.cnki.1000-4092.2026.02.022

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  In the high water cut development stage of oilfields，selective water shutoff technology is crucial for enhancing oil recovery. Emulsion-based water shutoff technology has emerged as a research and application hotspot due to its advantage of selective plugging. This paper systematically reviewed the mechanisms of selective water shutoff using emulsions，including core viscosity increase and mobility control，physical plugging and Jamin effect，and rock wettability alteration. The influences of various factors on emulsion stability，such as emulsifier type，pH value，temperature，salinity，and crude oil composition，were analyzed in detail. Traditional emulsion-based water shutoff systems （active heavy oil-based and emulsion-based） and their stabilization technologies were summarized and compared. Furthermore，novel heavy oil emulsion phase inversion water shutoff systems were introduced，and the phase inversion mechanisms and technical progress based on salinity and pH control were discussed.

• Research Progress on Non - acid Plugging Removers for Oilfields

  SUN Tao, WU Hongjun, ZHANG Bao, LIU Wan, YANG Yi, CHEN Kun, ZHOU Hexiang

  2026,43(2):370-380, DOI: 10.19346/j.cnki.1000-4092.2026.02.023

  Abstract: (2) HTML (0) PDF (0.00 ByteKB)(0)

  Abstract:

  Aiming at the increasingly prominent scaling and plugging problems in oil and gas field development，non-acidic plugging removal agents with chelating agents as the core component present significant technical advantages in treating acid-insoluble scales such as barium sulfate and strontium sulfate scales，protecting wellbore equipment，and reducing corrosion risks. At present，conventional non-acidic plugging removal fluids used in oil and gas fields are mainly based on traditional chelating agents such as ethylenediaminetetraacetic acid （EDTA） and diethylenetriaminepentaacetic acid （DTPA） . However，large-scale popularization and application are significantly restricted by high cost and limited environmental adaptability. The introduction of quantum chemical methods such as density functional theory （DFT） provides an efficient and accurate technical approach for the molecular design and performance optimization of chelating agents，which can offer important theoretical and technical support for the development of high-efficiency green plugging removal technologies for oil and gas fields. This paper systematically reviews the current status of reservoir scaling and scaling prediction technologies，focuses on the research progress and field application effects of non-acidic plugging removal agents，and discusses the design ideas and application value of chelating agents based on molecular computing techniques.

• Study on the Anti Swelling and Shrinkage Swelling Mechanism of DSJ-1

  ZHAO Kaiqiang

  Abstract: (768) HTML (0) PDF (0.00 ByteKB) (1159)

  Abstract:

  For reservoirs with high shale content and low permeability, many reports have pointed out that shrinkage swelling agents can reduce pressure and increase injection, but there is no research report on the relevant mechanism. In this paper, the effect of DSJ-1 shrinkage swelling agent addition on anti swelling ratio and shrinkage swelling ratio was investigated, and the bentonite before and after treatment were characterized by XRD, XRF, zeta potential, thermogravimetry, particle size distribution and optical microscope. Through characterization, the anti swelling and shrinkage swelling mechanisms were analyzed. It was found that DSJ-1 was mainly adsorbed on the clay surface during the anti swelling treatment, and the adsorption amount and zeta potential had the greatest impact on the anti swelling rate. During the shrinkage swelling treatment, DSJ-1 was mainly adsorbed between crystal layers, and the particle aggregate size and zeta potential affected the shrinkage swelling rate.

  • 1
• Molecular design, performance and mechanism study of electrostatic effect enhanced film-forming sand control agent

  SONG Jinbo

  Abstract: (753) HTML (0) PDF (0.00 ByteKB) (1092)

  Abstract:

  Aiming at the problems of complex injection procedure, high cost, great damage to formation permeability of traditional chemical sand consolidation agents, and weak adsorption capacity and short validity of polymer sand control agents, the existing polyamide polymer sand control agents were designed and modified by molecular simulation and experiment. The synthesis, structure characterization, performance test and formula optimization of quaternary ammonium modified and strengthened polyamide sand control agents were completed, and the mechanism of sand control agent with enhanced film formation was determined.

  • 1
• Thinking on shale gas fracturing flowback fluid treatment technology under carbon neutral vision

  DONG Yuan-wu, TANG Shan-fa

  Abstract: (819) HTML (0) PDF (0.00 ByteKB) (1192)

  Abstract:

  With the development of carbon neutralization goals in China, petroleum is facing a lot of pressure to reduce carbon emission. This study shale gas fracturing fluid flowback low carbon as the goal, shale gas fracturing fluid flowback were analyzed characteristics and potential impact on water quality, and probes into the existing processing technology and principle are reviewed, and points out that the shale gas fracturing fluid flowback process should reduce the pollutant emissions, energy recovery and utilization, saving energy and reducing consumption three aspects, It is suggested that the application of less or no water fracturing technology, clean fracturing fluid technology, new microbial treatment technology, energy saving treatment technology of fracturing flowback fluid, new energy replacement technology and energy saving technology of intelligent equipment in the development of oil and gas fields should be vigorously developed and promoted to ensure the reasonable development and sustainable development of shale gas.

  • 1
• Synthesis and performance evaluation of guar gum modified with glycidyl surfactant in seawater-based fracturing fluids

  Zhang Yongtao, Qiu Shoumei

  Abstract: (649) HTML (0) PDF (0.00 ByteKB) (1210)

  Abstract:

  In response to the problem that a large number of metal ions in seawater adhere to the surface of guanidine gum, which inhibits the swelling of guanidine gum molecular chains and cannot meet the continuous mixing in the field, epichlorohydrin and octadecenoic acid amidopropyl dimethyl as raw materials were synthesized and cationic monomer GOA was obtained, and then GOA was grafted onto guanidine gum molecular chains to obtain seawater-based fracturing fluid thickener epoxy propyl surfactant modified guanidine gum. Coulombic forces and electrostatic repulsion on the molecular chains of the modified guanidine gum prevented metal ions from attaching to the molecular chains of the guanidine gum, ensuring the swelling of the guanidine gum molecules and improving the salt resistance of the guanidine gum. The dissolution, salt resistance, temperature and shear resistance, sand-carrying and glue-breaking properties of GOA modified guanidine adhesive were investigated in the paper. The results show that the dissolution rate of GOA-modified guanidine gum in seawater is significantly higher than that of ordinary guanidine gum, and the median particle size in seawater is about 1/5 of that of ordinary guanidine gum molecules; the viscosity of GOA modified guanidine gum can reach 80% of the final viscosity after 5 min of swelling at 500 r/min; microscopic analysis shows that GOA-modified guanidine gum forms a clearly visible irregular mesh nematic structure, and the guanidine gum molecular chain The microscopic analysis showed that the GOA modified guanidine gum formed a clearly visible irregular net-like nematic structure, and the molecular chains of guanidine gum were fully expanded and the cross-linked bonds increased. The viscosity was still higher than 50mPa·s after continuous shearing at 160℃ and 170s-1 for 120min, indicating that the GOA modified guanidine glue fracturing fluid has good salt, temperature and shear resistance and the viscosity of the broken fluid is 1.6mPa·s. The residue content in the broken fluid is 297mg/L, which meets the requirements of field fracturing construction.

  • 1
• Detection Method of Olefin Sulfonate Used in Oil and Gas Field by Liquid Chromatography-Mass Spectrometry

  Zhang Xiaobin

  Abstract: (1008) HTML (0) PDF (0.00 ByteKB) (1233)

  Abstract:

  Aiming at the disadvantages of traditional titration detection methods such as low sensitivity, poor anti-interference ability, and long detection period, this paper uses liquid chromatography tandem quadrupole mass spectrometer to establish a detection method for α-olefin sulfonates used in oil and gas fields, and realizes the detection of target concentration in olefin sulfonate products, injection fluid and produced fluid. The detection conditions are as follows: the chromatographic column is an anionic column; the mobile phase is 55% methanol + 45% 8 mmol/L ammonium acetate aqueous solution (volume ratio), isocratic Elution; mass spectrometry detection conditions are electrospray ion source, negative mode, full scan. The recovery rates of this method for olefin sulfonate products, injection fluid, and produced fluid were 82.63-96.37%, 78.60-95.41%, 82.68-95.72%, respectively. One sample detection was completed in 8 minutes, and the lower limit of quantification was 5 ppm. And polymer, trace oil, etc. have no effect on the detection result, that is, the method is fast, sensitive, and has strong anti-interference ability.

  • 1
• Study on a Noval Solid-free Polymer Gel System for Grouting in Luohe Formation Sandstone

  LI Jiaming, ZHAO Guang, DAI Caili

  Abstract: (926) HTML (0) PDF (0.00 ByteKB) (1817)

  Abstract:

  The frequent water gushing in sandstone mining strata of Luohe Formation has seriously affected the safety production of the mine. The traditional grouting systems are faced with the problems of serious percolation effect and uncontrollable gelation performance, which is difficult to achieve effective regulation of fissure water. In this work, the microscopic characteristics of sandstone pores are clarified by analyzing the mineral composition and microscopic morphology of typical core samples. A solid-free polymer gel system with low cost and excellent stability is constructed for grouting, and the grouting performance evaluation is further carried out. The results show that the small pore diameter and poor connectivity are the geological reasons for the difficulty of smooth injection and long-distance migration of the traditional grouting systems. The noval polymer gel system with low cost, solid-free and easy injection for grouting can achieve gelation within 48h and has excellent long-term aging stability. The system has good injectivity and the pressure attenuation is not obvious after continuous flooding, with the plugging ratio remaining above 80 %. The system increases the seepage resistance and blocks the subsequent fluid by occupying the large channel or fracture space, which realizes the effective plugging of the water layer. The results of this work provide new ideas for the grouting and water plugging in Luohe Formation sandstone.

  • 1
• Construction and performance of high stability supercritical CO2 Foam for channeling blocking during CO2 flooding

  LI Weitao

  Abstract: (1364) HTML (0) PDF (0.00 ByteKB) (1878)

  Abstract:

  Aiming at the problems of low sweep efficiency of CO2 flooding and poor performance of conventional foam profile control ability, a high stability supercritical CO2 foam system composed of amphoteric surfactant HSD and modified SiO2 nanoparticles is constructed. Low permeability reservoirs in Shengli Oilfield are buried deep and have high temperature.The system showed good high-temperature resistance. At 120 ℃, the concentration of 0.5% nanoparticles increased the half-life of foam from 17 minutes to 40 minutes, and the stability was improved by nearly 2.5 times. The increase of reservoir pressure can increase both bubble volume and foam stability. Based on the power law model, the effect of nanoparticles on the rheological properties of supercritical CO2 foam system was studied. The results showed that the apparent viscosity of the system increased with the increase of the concentration of nanoparticles under the same shear rate, and the consistency coefficient increased from 0.073 to 1.22. The change rule of apparent viscosity of supercritical CO2 foam in porous media is simulated through core displacement experiment. The steady-state apparent viscosity of foam in porous media increases with the increase of nanoparticles. The foam of supercritical CO2 foam is stacked and discharged in "granular" shape. The size of foam is about 10 ~ 20um. Finally, the mechanism of nano particles enhancing the stability of CO2 foam was confirmed through experiments. The hydrophilic nano silica had interfacial activity due to the adsorption of surfactant molecules, which was adsorbed from aqueous solution to the gas-liquid interface, thus improving the stability of foam.

  • 1
• Recent progress in synthesis of oligomeric cationic surfactants

  QIAO Fulin

  Abstract: (1265) HTML (0) PDF (0.00 ByteKB) (1563)

  Abstract:

  In recent years, oligomeric surfactants, as a novel class of surfactant with superior efficiency at very low concentration, have shown promising applications in the fields of enhance oil recovery, pharmaceuticals, corrosion inhibitors, and so on. Oligomeric surfactants are composed of two or more amphiphilic moieties, which are chemically linked by a spacer group, and they bridge the gap between monomeric surfactants and polymeric surfactants. With the help of the spacer group, the spatial distance of multiple amphiphilic moieties becomes closer, contributing to the stronger aggregation ability of the oligomeric surfactants. Meanwhile, the structures of the spacer group and the topological configuration are more diversified, resulting in multifarious transition processes of molecular configuration and aggregation morphology. These characteristics make them show unique advantages as highly-efficient oilfield chemicals and stimuli-responsive soft materials, but the difficult synthesis processes have been identified as the bottleneck of their systematic investigations. In this review, the synthesis methods of linear, star-like and ring-type oligomeric cationic surfactants, which are classified by the spatial topological structure, are summarized in detail, and a brief review of future perspectives on the oligomeric surfactants are also discussed.

  • 1
• Research status and prospect of lost circulation formation drilling fluid plugging materials

  LIU Jing, MA Cheng

  Abstract: (1222) HTML (0) PDF (0.00 ByteKB) (2002)

  Abstract:

  Lost circulation is the main technical problem that restricts the improvement of the quality and efficiency of oil and gas drilling engineering. Improving the success rate of one-time plugging is an urgent need to ensure "safe, efficient and economic" drilling in global oilfields. Aiming at the study of drilling fluid leakage mechanism, the drilling fluid leakage mechanism is systematically summarized. Through the research of domestic and foreign scholars in recent years, plugging materials such as bridging, high water loss and curable have been developed. The properties and interaction mechanism of various plugging materials such as bridging, high water loss, curing, polymer gel, etc. are systematically introduced. The existing problems of plugging materials are clarified, and the future development direction of plugging materials is proposed.

  • 1
• Low interfacial tension small molecule oil displacement agent to improve oil recovery in low permeability reservoir

  MENG Wenyu, TANG Shanfa

  Abstract: (1020) HTML (0) PDF (0.00 ByteKB) (1877)

  Abstract:

  Poor injection of low permeability reservoirs, low efficiency of wash oil, water flooding can effectively improve recovery factor and so on question, this paper proposes a low interfacial tension of small molecular oil displacement agent (LST) new technology improve the recovery factor of low permeability reservoir, the interfacial activities of evaluation of the oil displacement agent, viscosity, emulsification, wettability and its reservoir environment adaptability and oil displacement effect. The results show that the oil displacement agent has good interfacial activity and viscosity. When the mass fraction is 0.4%, the oil-water interfacial tension is as low as 0.012mN/m-1, and the viscosity is close to that of the reservoir oil (3.4mPa?s). The oil displacement agent also has good oil-water emulsification ability, little influence of static adsorption on interfacial activity and viscosity enhancement, and good hydrophilic wettability, which can effectively improve water recovery efficiency at low dose or cost. By injecting 0.4%LST(0.4PV), the water flooding recovery of homogeneous core (50mD) can be increased by 11.210%, and the comprehensive water

  • 1
• Performance Evaluation of Gel Plugging System for High Pressure Water Injection Well

  WANG Wanfei, FU Hong

  Abstract: (1002) HTML (0) PDF (0.00 ByteKB) (1905)

  Abstract:

  In order to meet the strength, gelation time and gel breaking performance requirements of gel plugging system for high pressure water injection wells under pressure, a temperature-resistant and salt-resistant gel plugging system was prepared by using AM / AMPS ( acrylamide / 2-acrylamide-2-methylpropanesulfonic acid ) as binary polymer system and Smel30 (Trihy-droxymethyl compound) as crosslinking agent. The effects of temperature, inorganic salt, simulated oil content and shear time on gelation time and gel strength of the gel system were studied. At the same time, the effect of dosage of gel breaker sodium persulfate on gel breaking effect of gel system was studied. The results showed that the gelation time was shortened with the increase of temperature. When the temperature was 60 °C, the gelation strength was 73.5Pa and the gelation time was 7 h. The addition of inorganic salts reduced the distance between polymer chains, shortened the gelation time, and slightly increased the gel strength. The influence of three salts on gelation time and gel strength was NaCl < MgCl2 < CaCl2; the system has strong resistance to oil pollution; after shearing for 60 min, the gel strength can still maintain more than 81 %, which has strong shear resistance. The gel system did not dehydrate after 15 days of aging and still had strong gel strength; sodium persulfate can be used as a gel breaker with high efficiency and low cost, and the apparent viscosity of the residue is less than 64.4 mPa·s.

  • 1
• Study of Surface-active Injection Enhancement System for Reservoirs with Low Permeability and High Salinity

  ZHANG Guoqing, GONG Zhuoting, YI Xiao, WANG Zhengliang, ZHENG Yancheng

  Abstract: (1046) HTML (0) PDF (0.00 ByteKB) (1547)

  Abstract:

  Low permeability reservoirs have the characteristics of small pore throat radius, low permeability and water absorption ability. In order to improve the recovery efficiency of chemical flooding, a compounded system of alcohol ether sulfonate and betaine surfactant was established. The alcohol ether sulfonate DP6E6S characterized by 1H NMR was obtained by the introduction of propylene oxide and ethylene oxide into dodecanol and sulfonation. It was compounded with cetamide betaine PNC to evaluate surface properties, interaction properties, interface properties, wettability and emulsification properties of the complex system and the injection enhancement was obtained by core flooding experiments. It is showed that PNC and DP6E6S have strong synergistic effect of reducing critical micelle concentration (cmc) and surface tension effectively. The interfacial tension of the compound system decreases with the increase of salinity, especially n(PNC): n(DP6E6S) =2:3 and 1:1 which can reach 10-3 mN?m-1 in a wide range of salinity (>5%). The mole ratio of n(PNC): n(DP6E6S) =2:3 and 1:1 formed the more volume phase emulsion showed the best dissolution effect. The particle size of emulsion droplets first decreases and then increases with the increase of salinity. The interfacial tension of the compounded system is still low after core adsorption showed good adsorption resistance. The mole ratio of n(PNC): n(DP6E6S) =1:1 with larger wetting angle and smaller capillary force is conducive to depressurization and injection enhancement. The depressurization rate of the two optimized systems can reach 28.9% and 23.9%, respectively, indicating that low interfacial tension and high wetting angle are conducive to depressurization and injection enhancement of low permeability reservoirs.

  • 1
• Mechanical strength of polyacrylamide composite hydrogel reinforced by nanocrystalline cellulose

  MA Yanqi, LIN Meiqin

  Abstract: (1227) HTML (0) PDF (0.00 ByteKB) (1985)

  Abstract:

  The strength of gels determines its use and high mechanical strength gels have been applied in many fields. In order to enhance the strength of acrylamide (AM) gels, nanocrystalline cellulose (NCC) was used to prepare the AM/NCC composite hydrogel.The effects of NCC on the tensile properties, compressive properties, adhesion properties and viscoelastic properties of AM/NCC composite hydrogels were investigated by using texture analyzer and rheometer, and the microstructure of the composite hydrogels was observed by scanning electron microscope (SEM).The results showed that the tensile strength, compressive stress, adhesion and viscoelasticity of AM/NCC composite hydrogel were significantly higher than those without NCC. When the mass ratio of AM to NCC was 5:3, the tensile strength, compressive stress and viscoelasticity of the composite hydrogel reached the maximum. The toughness of AM/NCC composite hydrogel was significantly enhanced, and the tensile stress and adhesion force were nearly 4 times higher than those of AM gel.The strength of AM/NCC composite hydrogel is related to its microstructure, and the network structure of AM/NCC composite hydrogel is significantly denser than that of AM gel.

  • 1
• Construction and Performance Evaluation of Emulsification-Stripping Dual Effect System for Heavy Oil

  HU Junjie, ZHANG Guicai

  Abstract: (1170) HTML (0) PDF (0.00 ByteKB) (1775)

  Abstract:

  There are some problems in the development of the heavy oil reservoir in Shengli Oilfield, such as high viscosity and poor fluidity of crude oil, which the recovery efficiency of the water drive is not ideal. Therefore, the emulsification-stripping system was constructed with the instability coefficient of emulsification, the shrinkage rate of oil film and the minimum emulsifying speed as indexes. The emulsification and stripping ability of different surfactants for heavy oil were evaluated. The compound system of 0.3wt%CBT/ASC（m（CBT）：m（ASC）=3:2） was optimized. The displacement effect of the emulsification-stripping system was evaluated by the laboratory sand-filling flow experiment. The mechanism of its action was studied by a microcosmic model. The results showed that CBT had excellent emulsification performance and significantly reduced interfacial tension for heavy oil, and ASC had good stripping ability for heavy oil. The compound system has excellent emulsification-stripping function, and the enhanced oil recovery rate can reach 14.18%. The research results have important guiding significance for efficient development of heavy oil reservoir.

  • 1
• Screening and evaluation of cheap nutrient system for sandstone reservoir in well block LQ, Xinjiang

  WANG Hongbo, MA Ting

  Abstract: (749) HTML (0) PDF (0.00 ByteKB) (1823)

  Abstract:

  According to the nutritional requirements of the main oil recovery functional bacteria in the sandstone reservoir of LQ well block, the optimal carbon source, nitrogen source and phosphorus source were selected through single factor experiment, and the concentration of each component was preliminarily determined, on this basis, the significant influence factors of each component were analyzed by Plackett-Burman experiment and factor removal experiment, and the concentration of each component was determined, finally, response surface test was used to determine the concentration of each component, the final concentration was obtained by further optimizing each component according to the factors. The results showed that the selected nutrient system had good emulsifying effect, the main oil recovery function gene hydrocarbon oxidation gene reached 10_⁷copies/ml, and the physical model oil displacement experiment improves oil recovered by 11.65%. This study provides a good technical support for the field test of microbial flooding in well block LQ.

  • 1
• Research progress of drag reducers for fracturing and its drag reduction mechanism

  SI Xiaodong, LI Mingzhong

  Abstract: (2060) HTML (0) PDF (0.00 ByteKB) (2205)

  Abstract:

  Drag reducer is the key additive of fracturing fluid for unconventional reservoir reconstruction, such as tight sandstone and shale, and its performance will directly influence on the fracturing operation effect. The advantages,disadvantages and application of different drag reducers were analyzed. The turbulent drag reduction and drag reduction failure mechanism of drag reducers were emphatically described. The research progress of nanomaterials in fracturing drag reduction was summarized. This paper points out that in unconventional reservoir fracturing environment such as high temperature, high shear and complex medium, the new type of multi-functional composite drag reducers with the advantages of stability, high efficient drag reduction, low reservoir damage, strong sand carrying capacity, easy flowback and easy recycling will be an important research direction in future.

  • 1
• Effect of autogenous heat system on fracturing fluid gel breaking performance

  SHEN Xiulun

  Abstract: (1257) HTML (0) PDF (0.00 ByteKB) (2432)

  Abstract:

  Aiming at the problems of incomplete fracturing and low flowback ability in low-temperature shallow oil and gas wells, the heat generation of three different autogenous heat generation systems, including nitrite and ammonium salt, chromium trioxide, glucose, and hydrogen peroxide, was investigated. And the impact on the fracture gel breaking performance. The experimental results show that the heat generation of the heat generating system of nitrite and ammonium salt is the highest, and the temperature can reach above 80℃. In addition, the order of addition of three different heat generating systems and breakers is also determined in the experiment to make fracturing The liquid gel breaking effect is the best. Among them, the order of adding the heat generating system of glucose and chromium trioxide and the heat generating system of nitrite and ammonium salt is to add the heat generating system first, then add the APS breaker and hydrogen peroxide heat generating system. The order of addition is to add both autogenous heat system and APS breaker at the same time; finally, it is concluded that the autogenous heat system of nitrite and ammonium salt is the best additive for fracturing fluid gel breaking system, which can reduce the viscosity of fracturing fluid to 6 Below mPa.s, the best glue breaking performance.

  • 1
• Development and application of double-protection weighting agent for drill-in fluidZhuo Lvyan You Zhiliang Zhao Cheng

  ZHUO Lvyan

  Abstract: (947) HTML (0) PDF (0.00 ByteKB) (1821)

  Abstract:

  The arsenic content of barite supplied in China mostly exceeds the filter value of Second type of construction land in‘GB 36600-2018 Soil environmental quality Risk control stardard of soil contamination of development land’. Iron ore powder and ilmenite powder are commonly used as weighting agents, but they wear drilling tools seriously, which affects the electrical measurement results, and the chroma of drilling fluid is not up to standard after use, so they are rarely used now. Calcium carbonate is also a common weighting agent, due to its low viscosity, the viscosity effect is obvious, which has an impact on drilling. In view of the shortcomings of the environmental protection performance and application performance of the weighting agent, choose calcium carbonate weighting agent,adding barite into it proportionally,after surface coating modification, dry activation treatment and other production processes, The viscosity effect and the arsenic content is reduced.At the same time, it is beneficial to the hydrocarbon reservoir protection characteristics of calcium carbonate weighting agents . Innovation has formed a double-protection weighting agent that protects oil and gas reservoirs and the environment.The technology has been applied to 10 wells,all wells were drilled safely. Compared with the average value of adjacent wells, the penetration rate increased by 10%, the average hole diameter expansion rate decreased by 1.8%, the average oil production per meter of single well increased by 0.60t, and the arsenic content of mud cake reached the standard screening value (less than 60mg/Kg).

  • 1
• Optimization of synthesis conditions and evaluation of indoor oil displacement effect of a supercritical carbon dioxide thickener

  Fu Hong

  Abstract: (1195) HTML (0) PDF (0.00 ByteKB) (1487)

  Abstract:

  carbon dioxide flooding (CO2) is an effective means to further develop old oilfields with high water cuts and improve oil recovery based on tertiary oil recovery. Aiming at the gas channeling problem caused by the large viscosity difference between carbon dioxide and crude oil, a supercritical carbon dioxide thickener agent P-1 that can be applied to oil flooding was prepared. Through orthogonal experimental analysis, it is concluded that the amount of initiator has the greatest influence on the molecular weight distribution of the reaction, the optimal molar ratio of the synthetic monomer is 4:1:1, the molecular weight distribution is 1.12, and the yield is 88%. The synthesized product under optimal conditions was characterized by infrared characterization, and the characteristic absorption peaks matched the product. The evaluation results show that the saturation solubility of P-1 in supercritical carbon dioxide is 2.30%, and the minimum miscible pressure is 7.77Mpa.The thickener with a monomer concentration of 0.2% increased the viscosity of supercritical carbon dioxide by 42 times at 30Mpa, 50℃, the viscosity was 1.1675mPa.s, and the viscosity retention rate was 46.41%, while the temperature was raised to 110℃. Simulating the formation environment (15MPa), adding the thickening agent P-1 with a mass concentration of 0.2% can effectively improve the oil displacement effect of supercritical carbon dioxide flooding, and the lower the permeability, the more significant the extraction effect. In the same core, the total recovery degree of supercritical carbon dioxide flooding is more than 10% higher than that of supercritical carbon dioxide flooding after water flooding.

  • 1
• Experimental on lubricating oil for drilling fluid based on aging oil

  Jiaxue Li

  Abstract: (862) HTML (0) PDF (0.00 ByteKB) (1760)

  Abstract:

  Aging oil, a by-product of oil field surface production, has complex interface characteristics and is difficult to be dehydrated. Using aging oil to develop drilling fluid lubricant can make use of its emulsifying stability and avoid the problem of removing mud, sand and water from aging oil.Through a large number of experiments, the key emulsifier of drilling fluid lubricant based on aging oil is OP-4, the wetting agent is ABS, and the stabilizer is Na-CMC. The experiment determines that the best formula of the drilling fluid lubricant is 100ml drilling fluid + 3ml aging oil + 1.5g OP-4 + 0.15g ABS + 0.015gNa-CMC. Through the benchmarking national standard experiment, the developed drilling fluid lubricant based on aging oil meets the requirements for lubricants in the standard. Using aged oil as base oil to develop drilling fluid lubricant is a feasible resource treatment scheme for aged oil, which has great application value.

  • 1
• PREPARATION OF HIGHLY POROUS NI-MO CATALYST BASED ON γ-AL₂O₃ AND ITS CATALYTIC EFFECT ON ULTRA-HEAVY OIL VISCOSITY REDUCTION

  Yuan Chengdong

  Abstract: (790) HTML (0) PDF (0.00 ByteKB) (1663)

  Abstract:

  The ultra-heavy oil reservoir in Tahe Oilfield is currently producing by mixing light oils with ultra-heavy oils in wellbore to reduce viscosity. However, the high ratio of needed light oils and abnormal fluid production caused by uneven mixing make the production low efficient and high cost. To solve this challenge, in this work, we proposed the technology of catalytic ex-situ upgrading for viscosity reduction + reinjection of upgraded oil into wellbore to save the amount of injected light oils and improve the recovery efficiency. To develop a catalyst system that can effectively reduce the viscosity of the ultra-heavy oil and achieve high-level ex-situ upgrading, a Ni-Mo catalyst with high porosity based on γ-Al2O3 carrier was developed and its catalytic effect on the ex-situ upgrading and viscosity reduction was evaluated. The results show that the developed Ni-Mo catalyst can reduce the viscosity of ultra-heavy oil at 50 ℃ from 28200 mPa.s to 298 mPa.s. The viscosity is reduced by nearly 100 times, and the viscosity reduction rate is 98.94%. The density is decreased from 1.007 g/ml to 0.8724 g/ml. At the same time, the content of saturates is significantly increased, and the content of resins and asphaltenes was greatly decreased. The developed catalyst system shows an excellent ex-situ catalytic upgrading effect for extra-heavy oil and has a great potential for field application.

  • 1
• Evaluation of inhibition effect of ionic liquid on asphaltene precipitation in crude oil under high temperature and pressure

  CAO Pengfu

  Abstract: (946) HTML (0) PDF (0.00 ByteKB) (1657)

  Abstract:

  ionic liquids have great potential to prevent asphaltene precipitation in reservoir development, but the inhibition effect of ionic liquids under high temperature and high pressure is not clear. Based on the calibration of the relationship between asphaltene content and absorbance in organic solvents, the inhibitory effects of two ionic liquids [bmim] Cl and [bmim] BR and two common commercial inhibitors on asphaltene precipitation in crude oil were evaluated by spectrophotometry, and the determination experiments of asphaltene precipitation at high temperature and high pressure were carried out with the best inhibitor and ratio concentration, The effects of ionic liquid on the initial pressure of asphaltene precipitation (AOP) and the size of asphaltene aggregate in formation crude oil and CO2 injected formation crude oil were studied. The experimental results show that the inhibitory effect of ionic liquid [bmim] BR on asphaltene precipitation is much higher than ionic liquid [bmim] Cl and two other commercial inhibitors, and the optimal concentration is 600 ppm. The AOP of pure formation crude oil is 28.7mpa. When [bmim] BR is added, the AOP decreases by 21.6%. When isopropanol is added to ionic liquid, the AOP decreases by 29.6%. The AOP of formation crude oil saturated with 30mol% CO2 is 31.6mpa, which is 10.1% higher than that of pure formation crude oil. When isopropanol and ionic liquid mixed solvent are added, the AOP decreases by 44.3%. Isopropanol can produce ternary interaction with [bmim] BR and CO2, improve the activity of [bmim] BR, greatly reduce the AOP of saturated CO2 crude oil, slow down the growth rate of asphaltene particle size, reduce the deposition depth and blockage degree of asphaltene in the wellbore, and introduce asphaltene deposition into more controllable nodes, which has broad application prospects. The results obtained provide a reference for the prevention and control of asphaltene deposition and rational and efficient development.

  • 1
• Oil contaminated soil treatment new technology-the applicability of the plant type microbial fuel cell research

  gaojie

  Abstract: (835) HTML (0) PDF (0.00 ByteKB) (1639)

  Abstract:

  Oil enters the soil during refining, storage, transportation and use, causing pollution. Oil pollutants are highly harmful and difficult to deal with. Plant Microbial Fuel Cell (PMFC) is proposed to solve this problem. The PMFC was constructed with oil-contaminated soil as anode sludge. By detecting the output voltage, power density, apparent internal resistance and oil removal rate, the battery plants and electrode materials were optimized, and the optimized PMFC was used to explore the oil concentration applicability and optimum scope of application. The results showed that the green dill in plants could not survive in the anaerobic environment of PMFC, while the electricity production and degradation properties of white crane taro-PMFC were better than those of Lentinus edodes-PMFC; Compared with carbon sponge-PMFC, the power generation performance and degradation performance of carbon felt-PMFC in electrode materials are significantly improved; PMFC with white crane taro as battery plant and carbon felt as electrode material is suitable for any oil concentration, and with the increase of oil concentration, the power generation performance and degradation performance of PMFC show a trend of increasing first and then decreasing. So there is an optimal oil concentration range of 5-10g/kg. PMFC technology provides a new idea for oil-contaminated soil treatment, which can effectively deal with soil pollution problems while generating electricity and achieve a win-win situation.

  • 1
• Study on low temperature degradation of HPAM gel by activation of persulfate

  ZHU Jianjun, WANG Yefei

  Abstract: (828) HTML (0) PDF (0.00 ByteKB) (1619)

  Abstract:

  Temperature is a key factor limiting the degradation of polymer gel. Aiming at the blockage caused by polymer gel in low temperature reservoirs, the system of TA activated persulfate was proposed to use as a plugging remover to degrade polymer gel in this work. First, the quenching experiment and the radical test were used to determine the mechanism to degrade the polymer; the second was to study the effect of persulfate concentration, TA concentration, temperature and anions in formation water on the degradation, and the optimal reaction concentration was selected according to the change of polymer gel’s degradation efficiency and the corrosion with the concentration; Finally, the degradation effect of the system was compared with the conventional polymer plugging removers. The results showed that TA activated persulfate can rapidly degrade the polymer gel at 35 ℃, and the superoxide anion radicals are the main active radicals in degradation reaction. Compared with other polymer plugging removers, the said system of TA activated persulfate could rapidly degrade polymer gel with mild corrosion in the low temperature reservoir.

  • 1
• Study on improving anti-pollution performance of shale gas well cementing cement slurry with surfactant

  HE Guanxi

  Abstract: (943) HTML (0) PDF (0.00 ByteKB) (1772)

  Abstract:

  When shale gas reservoir is developed by horizontal wells, due to casing eccentricity and irregular well diameter, the displacement efficiency of oil-based drilling fluid is usually low. It is inevitable that some oil-based drilling fluid will be mixed into cementing cement slurry and pollute the performance of cement slurry. Therefore, in order to improve the anti-pollution ability of shale gas cementing cement slurry, the indoor research on improving the anti-pollution performance of shale gas well cementing cement slurry with surfactant AFSG-1 was carried out with on-site oil-based drilling fluid and cementing cement slurry as the research object. The results show that the addition of on-site oil-based drilling fluid will seriously affect the fluidity, thickening time and slurry water mud properties of cementing cement slurry. The greater the proportion of oil-based drilling fluid, the more serious the pollution is; With the increasing amount of surfactant AFSG-1 in the cementing cement slurry, the anti-pollution ability of the cement slurry is gradually enhanced. When the mass concentration of surfactant AFSG-1 in the cementing cement slurry reaches 2%, and then 20% oil-based drilling fluid is added, the fluidity, thickening time and cement stone properties of the slurry are significantly improved compared with those without surfactant. In addition, the effect of surfactant afsg-1 on improving the oil-based drilling fluid pollution resistance of cementing cement slurry is significantly better than that of other commonly used surfactants. The results show that surfactant AFSG-1 can effectively improve the anti oil-based drilling fluid pollution ability of shale gas cementing cement slurry, improve cementing quality and ensure cementing safety.

  • 1
• Corrosion mechanism and performance evaluation of inorganic blockages by neutral chelating system

  Qu Ming, Hou Jirui

  Abstract: (1138) HTML (0) PDF (0.00 ByteKB) (1787)

  Abstract:

  Acidizing plugging removal technology is often used to solve the problems of reservoir pollution and lack of liquid supply caused by long-term development of carbonate reservoirs. Due to conventional acidizing technology is special for carbonate reservoir, the conventional acidification technology is prone to water lock, corrosion of pipe string and wellbore scaling in the production process, leading to reservoir damage and reducing reservoir productivity. Therefore, this paper developed a neutral chelating system to remove inorganic plugging without backflow and secondary damage to the formation. Composing of chelating agent EDTA and corrosion inhibitor PAA, and a small amount of stabilizer Na2SO3 was added. It was prepared by deionized water fusion filtration, dehydration grinding and grinding at 120℃ and roasting activation at 500℃. The experimental results show that the system has good corrosion ability for inorganic plug such as Ca2+、Mg2+ ion, the corrosion rate is up to 95% within 24h at normal temperature. The corrosion rate of N80 steel is 4.45g/m2·h after 12h at 90℃. The average dissolution rate of natural carbonate cores can achieve more than 70%. Therefore, neutral chelation plugging removal system has a good potential for field application.

  • 1
• Viscosity Prediction Model for Water-in-Oil Emulsion Based on Quantitative Characterization of Crude Oil Physical Properties

  LUO Haijun, WANG Zhihua

  Abstract: (1143) HTML (0) PDF (0.00 ByteKB) (1673)

  Abstract:

  Eight kinds of crude oils with different physical properties were used to prepare water-in-oil (W/O) emulsions. The viscosity characteristics of the W/O emulsions were measured by rheometer. The effects of temperature, water cut of emulsion and shear rate on the apparent viscosity of W/O emulsions were studied. The results show that the apparent viscosity of the W/O emulsion decreases with the increase of temperature, increases with the increase of water cut, and decreases with the increase of shear rate, showing the property of shear thinning. The power law model was used to describe the rheological properties of W/O emulsion, i.e, . With the increase of water cut of emulsion, the consistency coefficient K of W/O emulsion increased gradually, while the rheological property index n decreased gradually. With the increase of temperature, the consistency coefficient K decreased gradually, while the rheological property index n increased gradually. Based on the experimental data and quantitative characterization of crude oil physical properties, a viscosity prediction model for W/O emulsion was established which could be applied to different crude oil and different shear conditions. The prediction deviation of the model shows that the average relative deviation between the calculated viscosity value and the measured viscosity value is 8.1%.

  • 1
• Development and field application of anti-returning and plugging agents

  Zeng Guang, Wan Xiumei

  Abstract: (1014) HTML (0) PDF (0.00 ByteKB) (1820)

  Abstract:

  Aiming at the characteristics of shale gas plugging in Sichuan-Chongqing block, easy to blow back and high requirements for pressure, this paper developed a kind of ARP anti-return leakage plugging agent based on high softening point resin. It has the ability of deformation, cementation and curing. It can be used in combination with bridge plugging particles to cement and solidify with plugging agent particles in formation cracks to improve pressure bearing capacity and anti-return ability. The laboratory evaluated the dispersibility of the ARP plugging agent in the field oil-based drilling fluid and the bonding strength with the field leakage plugging agent, and tested the pressure bearing capacity and anti-return ability after the cementation was cured. According to the needs of field application, the density of ARP anti-return leakage plugging agent is determined to be 1.8g/cm3, the particle size is 0.5-2mm, and the optimal ratio is formed with the field plugging agent. That is, ARP anti-return leakage plugging agent accounts for 25 parts, and on-site leakage plugging agent accounts for 75 parts, and its bonding strength can reach 7.8MPa. When plugging 2-3mm natural cracks, the positive pressure can reach 8MPa, and the anti-reflection ability can reach 3.3MPa. At the same time, the on-site construction process is designed according to the material characteristics, and a good on-site application effect is achieved.

  • 1
• The corrosion inhibition performance and mechanism analysis of phenyl and benzoyl thiourea in hydrochloric acid

  Yu Yi

  Abstract: (1008) HTML (0) PDF (0.00 ByteKB) (1766)

  Abstract:

  The inhibition performance and mechanism of two thiourea-based derivatives, phenylthiourea (PHTU) and benzoylthiourea (BOTU) for 20# steel in 15% HCl solution were investigated by corrosion weight loss experiments, scanning electron microscope (SEM), and quantum chemical calculations. The results indicated that both PHTU and BOTU showed good inhibition performance for 20# steel in 15% HCl solution, and the corrosion inhibition rate could reach more than 83% at 2 mmol/L. The adsorption of PHTU and BOTU on the steel surface was in accordance with the Langmuir adsorption model, and the adsorption model was a mixed physical and chemical adsorption. Quantum chemical calculations results showed that the reactive sites in the corrosion inhibitor molecule were mainly distributed in the C=S double bond, C-N bond and the C=O double bond. The N atoms in the corrosion inhibitor can form physical adsorption with the steel surface through electrostatic gravity after being protonated by the acid. The high electron cloud density of C=S bond, C=O bond and phenyl group can provide electrons to form chemisorption with the empty d orbitals of iron atoms through coordinate and feedback bonds, which can then be stably adsorbed on the metal surface to form a protective film and inhibit the corrosion process.

  • 1
• Development and Function Mechanism of High Temperature Resistance Intercalation Adsorption Inhibitor

  Wang Xiao-Jun

  Abstract: (817) HTML (0) PDF (0.00 ByteKB) (2184)

  Abstract:

  High temperature resistance intercalation adsorption inhibitor has been developed for ?reducing wellbore instability caused by which conventional inhibitors could not controll effectively hydration of clay surface, There are a lot of strong adsorption groups and hydrophobic groups in the molecular structure of the new inhibitor, which was low molecular weight, non-toxic environmental protection and good thermal stability. The analysis of inhibition mechanism showed that, the new inhibitor,the electrostatic repulsion and short-range repulsion of surface hydration of clay can be effectively reduced by the combination of strong adsorption group and exchange of hydrated sodium ions.And by changing the surface tension and wettability of clay, the self-imbibition capacity and specific hydrophilicity of shale can be controlled, and the invasion of water phase can be reduced. Meanwhile.?the new inhibitor had strong adsorption and anti-desorption ability, could adsorb on the clay surface for a long time, improved the hydrophobicity of the clay surface, and reduced the invasion of free water. Laboratory evaluation experiments showed that the new inhibitor had good properties of inhibiting mud production, controlling clay hydration expansion and preventing mud shale collapse, which was beneficial to the stability of rheological property and borehole wall of water-based drilling fluid, it had a good application prospect.

  • 1
• Laboratory study on solid-free constant rheological drilling fluid with reservoir protection for deep-water drilling

  Chen Liang, You Fu-chang.

  Abstract: (790) HTML (0) PDF (0.00 ByteKB) (1743)

  Abstract:

  In the drilling process of deep-water oil and gas fields, due to the low temperature near the bottom mud line, it was easy to lead to the thickening, paste plugging, slurry running and other problems of drilling fluid. The thermosensitive thickening copolymer ASSN was prepared with acrylamide, N-vinyl caprolactam, diethylbenzene and sodium allyl sulfonate as raw materials. ASSN was combined with fenugreek gum , which had strong salt resistance and significant cutting effect, to form a flow pattern regulator with low temperature constant rheological properties, and formed a set of solid-free constant rheological drilling fluid with reservoir protection for deep-water drilling with other treatment agents. 0.5%ASSN+0.3% fenugreek gum as flow pattern regulator played a good role in regulating the rheological properties of drilling fluid at low temperature. Its low temperature control ability of drilling fluid was less affected by different weighting agents, and it had good compatibility with other drilling fluid treatment agents, so that the FLAPI of drilling fluid was only 5.2mL. And it had good resistance to contaminated soil, field drilling cuttings, salt and seawater intrusion and excellent reservoir protection (recovery value of field core permeability was greater than 95%).

  • 1
• Synthesis and Performance Evaluation of an Amphoteric Polymer Viscosity Reducer

  ZHANG Cheng, DUAN Ming

  Abstract: (1064) HTML (0) PDF (0.00 ByteKB) (2025)

  Abstract:

  In this paper, acrylic acid (AA), 2-acrylamido-2-methylpropanesulfonic acid (AMPS), and methacryloxyethyl trimethylammonium chloride (DMC) wereSusedSasSmonomers, based on the aqueous solution explosion polymerization process, a low molecular weight zwitterionic polymer viscosity reducer for drilling fluids was synthesized by using environmentally friendly tetramethylthiuram disulfide (TMTD) instead of sulfhydryl compound as the chain transfer agent. Taking the room temperature viscosity reduction rate as the evaluation index, the optimum synthesis conditions of the viscosity reducer have been determined: the monomer concentration was 55 wt%, the addition of TMTD was 0.75 wt%, the addition of oxidation-reduction initiator was 3 wt% of the monomer concentration, the neutralization of (AA+AMPS) was 50%, the addition of AMPS was 5.5 wt%, and the addition of DMC was 4.5 wt%. Under this condition, the number average molecular weight of the synthesized zwitterionic polymer viscosity reducer is 914 g/mol, and its viscosity reduction rate in the fresh water base slurry is 91.53%, and it has good temperature resistance, which can meet the temperature resistance requirement of 180 ℃. This research provides a green and environmentally friendly option for the synthesis of low molecular weight zwitterionic viscosity reducer.

  • 1
• Effects of CO₂ on the Aggregation Behaviorof Asphaltene Molecules in Heavy Oil

  JIANG Huixin, WANG Chuangye

  Abstract: (746) HTML (0) PDF (0.00 ByteKB) (2656)

  Abstract:

  The aggregation behavior of asphaltenes significantly affects the viscosity of heavy oil. Studying the aggregation behavior of CO2 on asphaltenes in heavy oil can further analyze the mechanism of CO2 displacement. Under different CO2 pressures and conditions, CO2 dissolution experiments were carried out on heavy oil and heavy oil added with benzene and ethanol as CO2 solubilizers. After separating the four components, CO2-treated asphaltenes were obtained. X-ray diffractometer, scanning electron microscope, transmission electron microscope and other analytical instruments were used to characterize the interlayer spacing, surface morphology and microstructure of asphaltene aggregates extracted under different experimental conditions, and the effect of CO2 on asphaltenes in heavy oil was analyzed. Influence mechanism of aggregation behavior. The results show that the dissolution of CO2 in heavy oil leads to an increase in the interlayer spacing of asphaltene aggregation stacking, which slows down the aggregation behavior of asphaltene molecules, thereby reducing the viscosity of heavy oil.

  • 1
• Research progress and prospects of lubricants in water-based drilling fluid

  WANG Kai, LI Xiaoming

  Abstract: (1197) HTML (0) PDF (0.00 ByteKB) (1707)

  Abstract:

  A great number of researches about eco-friendly and high-performance lubricant have been conducted to improve the lubrication of water based drilling fluids, solving the high friction of long horizontal section of horizontal wells and promoting the development of drilling technology for horizontal well. In this paper, the domestic and international research progress of lubricant for water based drilling fluids has been reviewed including the lubricants from alcohol ether, alkyl glycoside, modified vegetable oils, mixed lubricants, extreme-pressure lubricants, and encapsulated lubricants. The advantages and disadvantages of these lubricants are compared and the outlooks for the development of water based drilling lubricants are expected.

  • 1
• Laboratory Screening and Evaluation of Surfactant Flooding System with Salt Resistance

  ZHOU Ming

  Abstract: (935) HTML (0) PDF (0.00 ByteKB) (1693)

  Abstract:

  Aiming at the problems of unsatisfactory injection production ratio in the actual oil production and development process of Yanhua 182 Well Group, low production and low energy of development wells, high salinity, high calcium and magnesium ions in formation water resulting in the failure of conventional surfactant, a system of surfactant flooding with anti-salt was prepared. Without chelating agent and stabilizer, the system of surfactant flooding consisted of PPM-12（bis{[(N-methylN-(3- dodecanoxy-2-hydroxyl) propyl-N-(2-hydroxyl-3-sulfonic acid sodium) propyl] methylene} ammonium chlorides），AES-12 (sodium lauryl ether sulfate) and OB-2 (dodecyl dimethylamine oxide). The optimum total concentration of surfactant flooding system was 0.3wt%, and the suitable weight ratio range was 4:1:1-1:1:4. The optimum ratio is 2:1:3, and the oil-water interfacial tension can reach the lowest value (0.0012 mN.m-1). The adsorption, emulsification, salt resistance of the composite surfactant flooding system was studied under optimum conditions. The results of adsorption performance showed that the system was still in the order of 10-3 mN.m-1 after six adsorption. The results of emulsification showed that the water separation time of the system was 3995s. The experimental results of resistance to sodium, calcium and magnisesium ions showed that the system could reach the order of 10-3 mN. m-1 in the range of sodium, calcium and magnesium ions in the oilfield. Magnesium ions have the greatest influence on the interfacial tension of the system, followed by calcium ions and sodium ions. Experiments show that the PPM-12, AES-12 and OB-2 compound system is suitable for EOR of Chang 6 reservoir of Hua 182 well groups, with an average EOR of 10.3%. It has a good application prospect in similar high salt and low permeability reservoirs.

  • 1
• Synthesis and performance study of the high temperature-resistant acid gelling agents

  LI hui, LUO bin

  Abstract: (871) HTML (0) PDF (0.00 ByteKB) (1632)

  Abstract:

  Compared with other acid gelling agents, amphoteric gelling agents have the advantages of low price and convenient synthesis and can improve the viscosity of acid based on supramolecular effect of gelling agents. Hence, amphoteric gelling agents have wild application prospect in acidizing fracturing field. Two amphoteric gelling agents were synthesized from acrylamide (AM), 2-acrylamide-2-methylpropanesulfonic acid (AMPS), dimethyl diallyl ammonium chloride (DMDAAC) and methacryloyloxyethyl trimethyl ammonium chloride (DMC) by free radical aqueous solution polymerization. The results indicated that acid dissolving time of two amphoteric gelling agents less than 40 min. The viscous acid containing the compound of two amphoteric gelling agents mixed in a certain mass ratio was 39 mPa·s at room temperature (25°C) and 170S-1and was 15 mPa·s at 160°C and 170S-1 after continuous shear for 90min, which demonstrated that the compound had excellent viscosity increasing property, temperature resistance and shear resistance performance

  • 1
• The effects of wettability on water coning in bottom water reservoirs

  HU junjie, ZHANG guicai

  Abstract: (708) HTML (0) PDF (0.00 ByteKB) (1769)

  Abstract:

  The wettability of the rock has an important influence on the delay of the water coning recovery after the bottom water reservoir is pressed, but the degree of its influence is not clear. In view of this, four wetting adjustment systems with different wetting abilities were constructed with the contact angle as the index of wetting agent, which were dissolved in oil-soluble viscosity reducer, and their properties were evaluated. On this basis, the intrinsic relationship between wettability and production property conditions was quantitatively described, and the degree of influence of wettability on inhibiting water coning recovery was further illustrated. The results show that the reservoir under the action of oil wetting agent has the best effect of inhibiting bottom water recovery, the equilibrium pressure ratio reaches 3.75, and the net recovery degree increases by 15.17%. However, the equilibrium pressure ratio of the reservoir under the action of strong water wetting agent is only 0.54, and the net recovery is increased by 6.51%. There is an obvious regularity between wettability and produced physical properties. Adjusting the wettability of the reservoir can effectively restrain the rise of the water cone and improve the oil recovery.

  • 1
• Development and application of micro-expansion degradable gel temporary plugging agent for acid fracturing

  WU Wenchuan, YU Xiaorong

  Abstract: (1286) HTML (0) PDF (0.00 ByteKB) (1716)

  Abstract:

  Diversion acid fracturing is one of the effective measures to increase production of carbonate reservoir. Importantly, the key of this technology lies in the temporary plugging agent. However, the existing acid fracturing with temporary plugging agents are of poor acid resistance, complicated removal process, and high cost. Aiming at solving those problems, a micro-expansion temporary plugging agent (WDS) for acid fracturing was prepared through aqueous radical polymerization in this study. The degradation performance, temporary plugging performance, and reservoir damage of the WDS were studied, and it was applied in field construction. The results showed that it was first micro-expanded and then degraded in different solutions. The complete degradation time of the WDS reduced from 78 h to 45 h with the rising temperature from 70 ℃ to 120 ℃. The complete degradation time reduced from 75 h to 48 h with the rising concentration of HCl from 3% to 20%. According to the results of displacement experiment, with the increase of the injection, the temporary plugging pressure increased, and the time to reach the maximum temporary plugging pressure reduced. And with the increase of the fracture width, the temporary plugging pressure decreased, and the time to reach the maximum temporary plugging pressure increased. In addition, the WDS was less harmful to the core, and the permeability recovery value of cores of more than 90%. Furthermore, the field application results indicated that the construction pressure increased by 10 MPa after adding the WDS, and the effect of temporary plugging was remarkable. In conclusion, the WDS can be completely degraded under the conditions of temperature, acid, and salinity, and the effect of temporary plugging is remarkable. It has a good application prospect in diverting acid fracturing.

  • 1
• Synthesis, Characterization and Drag Reduction Properties of a Long-chain End-group Hydrophobically Associative Polymer

  YANG LIN

  Abstract: (884) HTML (0) PDF (0.00 ByteKB) (1644)

  Abstract:

  In order to develop a new type of slick water drag reducer, this paper uses terpolymer of acrylamide (AM), hydrophobic monomer dodecyl dimethylallyl ammonium chloride (C12DMAAC), and sodium acrylate (NaAA) as raw materials. The long-chain end-group hydrophobic associative polymer HPAM-L was synthesized by the self-made long-chain hydrophobic initiator AIBL. The performance was characterized, and the friction resistance of HPAM-L solution at different concentrations was measured by a flow loop friction tester. The results show that the viscosity-average molecular weight of HPAM-L is about 7.43 × 106 g/mol, the critical association concentration is about 1～1.5 g/L, and it has good temperature resistance and shear stability. The aqueous solution of HPAM-L has a wide range of Linear viscoelastic region, and the higher the concentration, the more obvious the elastic characteristics. When the solution concentration is 0.075%, 0.086%, 0.1% and 0.15%, the maximum drag reduction rate can reach 71.6%, 73.1%, 73.3% and 74.1%, respectively, and the drag reduction performance is good.

  • 1
• Analysis of Factors Affecting Silicon Removal by Hydroelectric Flocculation Depth in Ultra-heavy Oil Production

  YANG Changgen, FAN Yuxin

  Abstract: (946) HTML (0) PDF (0.00 ByteKB) (1692)

  Abstract:

  Electrocoagulation has been treated by experiment on deep silicon removal of super-heavy oil produced water using aluminum plates as cathode and anode. The optimal PAC dosage, pH value ,current density and PAM dosage are obtained through single factor variables. The results show that single electrocoagulation can not achieve deep silicon removal. Electrocoagulation together with PAC and PAM has a synergistic effect on the removal of silicon from super-heavy oil produced water. The effluent of SiO2 by electrocoagulation reaches 20mg/L and the SiO2 removal rate is 92% when the PAC is 200mg/L, the pH is 8.0, the current density is 10mA/cm2, and electroflocculation time is 13 minutes, which can achieve deep silicon removal. With the increase of electric flocculation time, the removal rate of SiO2 increases, but the rate of change decreases.

  • 1
• Synthesis and demulsification performance evaluation of nano iron sol stabilized by biosurfactant

  ZOU Jing, WANG Zhengliang

  Abstract: (930) HTML (0) PDF (0.00 ByteKB) (1728)

  Abstract:

  In view of the high cost and pollution of physical and chemical demulsifiers in the demulsification process of oilfield wastewater, it is necessary to study and synthesize new environmentally friendly demulsifiers. In this paper, a combination of sol-gel and solvothermal method is used to prepare biosurfactant (Biosurfactant, BS) stabilized nano-iron sol materials, to study the optimal BS concentration, and use SEM, XRD, FTIR, laser particle size analyzer, Zeta Potential etc. characterize the BS-stabilized nano-iron sol, and study its morphology, size, phase, functional group, sol stability, particle size distribution and other influencing factors. The demulsification performance of the synthesized nano-iron sol on the oily sewage emulsion prepared by the oil-water mixture on Weizhou Island was investigated. The results showed that after fermentation of the glycolipid biosurfactant T bacteria with a specific medium for 6 days, the supernatant after centrifugation was taken to synthesize iron sol. When the concentration of supernatant was 80 % and 100 %, iron particles with diameters of about 200 nm and 40 – 200 nm could be synthesized, respectively. When the concentration was 60 %, the demulsification effect of nano-iron sol product was the best. At low temperature, it could produce good demulsification effect on the oil-in-water emulsion formed by sodium dodecyl sulfate, and the dehydration rate reached 78 % after 24 h. It shows that the method used in this paper can synthesize BS stable nano-iron sol with good demulsification characteristics. It is suggested that biological metabolites and chemical agents should be combined organically in the future to prepare environmentally friendly composite nano-demulsifiers, while studying its repeated use and other issues.

  • 1
• Measurement of relative permeability curve of heavy oil - water by nuclear magnetic resonance

  Pu Wanfen, Chang Jiajing

  Abstract: (1003) HTML (0) PDF (0.00 ByteKB) (2618)

  Abstract:

  Relative permeability was an important basic measurement parameter in heavy oil development experiment. Due to the high viscosity of heavy oil, oil-water emulsification was prone to occur during water flooding process, which made it difficult to obtain the heavy oil-water relative permeability curve accurately. The traditional measurement method of relative permeability curve regarded the core as a "black box", and measured the volume of oil and water at the outlet by the method of manual reading or weighing, which had the disadvantages of low measurement accuracy and less information. In order to accurately measure the heavy oil-water relative permeability curve, this paper selected the long artificial sandstone core. Based on the nuclear magnetic resonance measurement technology, through the simultaneous calibration of crude oil and formation water of Bohai B reservoir, the unsteady state method was used to measure the heavy oil-water relative permeability curve, and the T2 spectrum test was carried out on the core and the produced fluid at the outlet. Thus, the pore volume (147.18cm³), irreducible water saturation (25.9%), residual oil saturation (43.83%) of the core and the oil and water content at the outlet were obtained more accurately, and the heavy oil-water relative permeability curve was obtained more accurately. Moreover, the D/T2 two-dimensional spectrum test was carried out on the produced fluid with oil-water emulsification, and the emulsification of oil and water was judged more accurately. The research results can provide some theoretical guidance for the development of heavy oil water flooding, which is beneficial to the study of the mechanism of heavy oil water flooding.

  • 1
• Preparation and Performance Evaluation of Depressurization and Oil-displacing Agent in Low Permeability Reservoir

  QU Huimin

  Abstract: (1019) HTML (0) PDF (0.00 ByteKB) (1885)

  Abstract:

  Affected by reservoir physical properties, there is a contradiction between the insufficient formation energy and difficult water injection in water flooding development of low permeability reservoirs. On the one hand, the water injection pressure is high and the underinjection is serious. On the other hand, the formation pressure drop of low permeability reservoirs is large, the productivity decreases rapidly, and the oil recovery rate and recovery degree are low. After water flooding, there are still many forms of residual oil such as membrane or oil droplets. In view of the above problems, this work synthesized metronidazole asymmetric Gemini surfactant, and combined with dehydro rosin surfactant, cetyl alcohol, ethanol to form a functional enhanced injection and oil displacement agent. The agent reduces the interfacial tension between oil and water, emulsifying crude oil and removing oil film. The cationic component forms molecular film on the rock surface with water as the transfer medium, stabilizes clay, improves the wettability of rock surface and reduces water injection resistance. Combined with the field test of pressure flooding, the daily oil increment of the well group is 13.4 t/d at the beginning and 12.6 t/d after 5 months. The injection capacity of the well was significantly improved. Before pressure flooding, the injection volume of the water well is 0 at the high pressure of 30 MPa, and 30 m³/d at 27.5 MPa after pressure flooding.

  • 1
• Plugging Mechanism and Prevention of Oil Well in Polymer Flooding Reservoir

  LIU Ying, WANG Zengbao

  Abstract: (881) HTML (0) PDF (0.00 ByteKB) (1875)

  Abstract:

  Polymer flooding widely used in oilfields for a long time corresponds to serious plugging of oil wells and decreased liquid volume, which seriously affects the further development of reservoirs after polymer flooding. Using XRD, SEM and other technical means to analyze the composition and composition of oil well plugging products; through different plugging fluid simulation and near-well reservoir condition simulation, the plugging degree and main controlling factors of oil well plugging are studied. The results show that the plugs in the oil wells of polymer flooding reservoirs are mainly polymer aggregates that are cross-linked and embedded to adsorb formation mineral salts and clays, accounting for 65.6%; followed by formation sand particles and cements, and crude oil, respectively, 17.8 %, 16.6%. The plugging of porous media caused by the formation of sand particles is the main controlling factor of plugging near the oil well. The polymer agglomerates formed by polymer derivative cross-linking and adsorption agglomeration aggravate the degree of blockage of the oil well. Based on the guidance of the research on the plugging mechanism of polymer flooding reservoirs, the near-well crude oil cleaning of plugged oil wells + the oxidative degradation of polymer micelles, the integrated prevention and control program of oil well plugging and sand control for the effective sand consolidation control of far wells has good application effects, and the average single well extraction 86.8%.

  • 1
• The Effect and Mechanism of Surfactants with Different Interfacial Properties to Improve Oil Recovery

  LIU Qian

  Abstract: (780) HTML (0) PDF (0.00 ByteKB) (2181)

  Abstract:

  Taking the low permeability tight reservoir of Chang 6 as the research object, two self-made surfactants S1 (with strong modification wettability) and S2 (ultra-low interfacial tension) with different interfacial properties were selected. Their static and dynamic permeability effects were characterized by NMR, and their oil displacement process was studied by 2.5-dimensional micro model, The EOR effect and mechanism of surfactants with different interfacial properties are analyzed. The results show that both S1 and S2 have good enhanced production effects. Imbibition is a process in which water enters small pores to replace oil to large pores. Surfactants can greatly promote the production of small pores; During oil flooding, the dominant channel is obviously formed, which can realize wettability reversal, and has additional imbibition effect, which greatly increases the sweep volume and oil washing efficiency, and can disperse the crude oil into small scale state. Among them, the S1 capillary with stronger wettability ability is more powerful and has a higher degree of mobilization of small holes, but the recovery rate is slower, but the additional imbibition during displacement is stronger, which can achieve ultra-low interfacial tension.The S2 with ultra-low interfacial tension can achieve smaller oil phase flow resistance, faster imbibition speed, and faster recovery to reach equilibrium.

  • 1
• Accelerating the dissolution of hydrophobically associative polymers by Cyclodextrin

  李玺

  Abstract: (1080) HTML (0) PDF (0.00 ByteKB) (2036)

  Abstract:

  Hydrophobically associating polymers are highly concerned for their excellent rheological performance. However, the poor dissolution caused by the interactions of hydrophobes restricts their popularization and application on oilfields. Irreversible viscosity loss of polymer solution will inevitably occur through the current physical accelerated dissolution modes. In this paper, cyclodextrins (CDs) are used to accelerate the dissolution of the hydrophobically associating polymer by the inclusion of hydrophobic groups, and avoiding solution viscosity loss. The inclusion of cyclodextrins on hydrophobes improves the interaction of associating polymers with solvents, and as the molar ratio of cyclodextrin to hydrophobic groups (CD: [H]) increases, the dissolution time of the hydrophobically associating polymer decreases exponentially. Rheology results have shown that CDs can significantly shorten the dissolution time of the hydrophobically associating polymers by disrupting association structures of hydrophobic groups through inclusion. Utilizing the competitive inclusion properties of cyclodextrin inclusion complex, the rheological properties of the solution can be completely restored by adding an appropriate amount of nonionic surfactants with stronger affinity to the CDs to the hydrophobes of associating polymer.

  • 1
• Performance evaluation and application of the microbial huff and puff system for Sheng li oil field Luo 9 Shi 1 block

  CAO Gongze, LI Caifeng

  Abstract: (898) HTML (0) PDF (0.00 ByteKB) (1746)

  Abstract:

  Luo 9 Shi 1 block has some problems of high temperature, high viscosity, high water cut and low water flooding efficiency.In order to improve the output of high water cut oil well, the composite system of biological polysaccharide and microorganism was developed. Its temperature resistance, plugging performance, emulsion viscosity role and model of the displacement effect were studied. Finally, the composite system of huff and puff was applied in the field.The results showed that the viscosity of the new biological polysaccharide remained in the range of 120 ~ 125mPa.s at 55 ~ 95℃ and the temperature resistance was strong.When the new biological polysaccharide injected into the core, the pressure increases by 5.6 times and the permeability decreases by 53.3%, which could effectively seal the core.When the ratio of microbial fermentation liquidⅠto microbial fermentation liquidⅡwas 1:2, the high temperature emulsification ability was the strongest and the emulsification viscosity reduction rate was 81.4%. The physical simulation of oil displacement experiment showed that the composite system of biological polysaccharide and microorganism improved oil recovery by 13.9%, which was better than the single system in oil displacement. The application results of five oil Wells showed that four oil Wells had achieved success and the cumulative increase of oil amounted to 2730t. The effect of increasing oil and dewatering was significant, which continued to be effective.It effectively improved the low efficiency of oil well in Luo9 Test 1 block.

  • 1
• Development and Evaluation of cryogenic Microbial Demulsification System in shale oil production fracturing fluid

  Gong Zhaobo, Ma Ting

  Abstract: (1686) HTML (0) PDF (0.00 ByteKB) (1917)

  Abstract:

  In order to meet the demand for demulsification in Xinjiang oilfields, and reduce the environmental pollution of common oilfield chemicals, this article based on environmental safety and the complex situation of shale oil fracturing produced fluids in the Madong block in Xinjiang, and fifteen kinds of biodemulsifiers synthesized by microbial fermentation were screened and evaluated by the bottle test method. The demulsification of the fermentation broth and the purified extract was compared, and the results showed that the biodemulsifier XJ-4-2 synthesized by the XJ-4 bacteria had good compatibility with the extracted fluid from the Madong block and more than 80% dehydration rate. In order to improve the demulsification efficiency and reduce the cost, a composite system of biological demulsifier and conventional chemical demulsifier is adopted. After optimization, the demulsification efficiency of the composite system of biological demulsifier XJ-4-2 and chemical polyether demulsifier reaches above 95％. Through the optimization of the dosing process, the initial water content is 43.76%. When the chemical demulsifier 200mg/L is added at 60 ℃, the dehydration rate after 2h sedimentation is 91.45%, the remaining water content ratio of crude oil was 8.43%, and the oil content ratio of sewage is 228mg/ L. The initial water content of the improved crude oil is 33.85%. At 50 ℃, when the compound formula 200mg/L is added, the dehydration rate after 2h sedimentation is 94.56%, the remaining water content ratio of crude oil 1.84%, and the oil content ratio of sewage is 156mg/L. In summary, the biological demulsifier has high dehydration rate at low temperature and low sewage oil content. It is of great significance for the efficient separation of produced fluids from fracturing exploitation of shale oil in the Madong block and ensuring the normal operation and economic benefits of the oilfield.

  • 1
• Static Adsorption of JCP-1 Nano-spheres on Mineral Surface in Liquid Phase

  JIANG Xu, CHEN Junbin

  Abstract: (719) HTML (0) PDF (0.00 ByteKB) (1693)

  Abstract:

  Nanospheres have been widely used in low permeability reservoir development. In order to study the adsorption mechanism of nano-spheres on rock and mineral surfaces, it is necessary to quantitatively characterize the influence of mineral types on the adsorption capacity of nano-spheres on rock and mineral surfaces. Firstly, starch - cadmium iodide method was used to calibrate the concentration of JCP-1 nano-microsphere emulsion, and then the adsorption capacity of the microspheres on the surface of single component mineral and multi-component mineral was determined respectively. Then, based on the measured data of microsphere adsorption on the surface of single component minerals, the predicted value of microsphere adsorption on the surface of multi-component minerals was obtained by weighted superposition according to the relative content of rock minerals. The results show that the static adsorption capacity of JCP-1 nanospheres on different mineral surfaces varies greatly. The adsorption capacity of clay minerals to microspheres is generally stronger than that of non-clay minerals. Kaolinite has the strongest adsorption capacity for this type of microspheres, which is 14.75 times stronger than quartz. The adsorption capacity of the microspheres on the surface of potash feldspar is much stronger than that of the other two non-clay minerals, and the variation value of adsorption capacity is 1.96 times and 8.42 times of that on the surface of albite and quartz, respectively. For the adsorption capacity of microspheres on the surface of multi-component minerals, the relative error between the predicted value of weighted superposition method and the measured value is within 3%. Finally, based on the adsorption phenomenon at solid-liquid interface during the migration of nanospheres in pore channels, it is considered that the clay minerals on the pore walls strengthen the adsorption of microspheres, which is beneficial to change the pore radius and achieve "partial fluid flow direction" under the condition of "incomplete plugging".

  • 1
• Cationic Surfactant Pretreats Formation to Enhance Squeeze Life of Scale Inhibitor

  SONG Haojun, REN Shaoran

  Abstract: (696) HTML (0) PDF (0.00 ByteKB) (1766)

  Abstract:

  In the process of seawater injection development in offshore oilfields, the incompatibility of injected water and formation water often leads to serious sulfate scaling in oil wells. Although the squeeze treatment can be used to prevent scale, the squeeze life of the scale inhibitor is generally shorter. This article considers adding an adsorption enhancer to the pre-flush to increase the adsorption capacity of the scale inhibitor in the formation and reduce the desorption speed of the scale inhibitor. Quaternary ammonium surfactant DTAC and cationic gemini surfactant GS-A6 were selected as adsorption enhancers, and sodium polyacrylate PAAS was selected as scale inhibitor. The compatibility experiment, static adsorption experiment and dynamic adsorption-desorption experiment of adsorption promoter and scale inhibitor were carried out. The results show that at 120℃, the two adsorption enhancers have good compatibility with the scale inhibitor, and the adsorption enhancer can effectively increase the adsorption amount of the scale inhibitor in the formation and prolong the squeeze life of the scale inhibitor. The adsorption enhancer DTAC was greatly affected by oil saturation, and the adsorption enhancement effect decreased significantly at high oil saturation. The adsorption enhancer GS-A6 has a stable adsorption enhancement effect under different concentrations and different oil saturation conditions, and is suitable for oil well scale inhibition in different development stages.

  • 1
• Integrated Thickener with High-Viscosity and High-Drag Reduction used for Fracturing Deeper Shale Gas

  WEI Juanming

  Abstract: (1123) HTML (0) PDF (0.00 ByteKB) (1676)

  Abstract:

  Slick water hydrofracking represents an important technique for the efficient development of shale gas, but there are a series of challenges such as low viscosity, large freshwater consumption and slick water-to-gel transition, which limit its application in hydrofracking of deeper (>3500 m) shale gas reservoirs. To address these issues, an integrated thickener with high-viscosity and drag reduction (HVFR) was synthesized by free radical polymerization, and their solubility, thickening ability, drag reduction and proppant carrying capability as well as heat- and shear-resistance were examined. The results showed that the viscosity-average molecular weight of HVFR is 22.7 x 10^6 g/mol, and the HVFR exhibited a rapid dissolution rate with thickening rate of 93% within 1 min, which is conducive to the online continuous mixing of fracturing fluid. At a flow rate of 150 L/min, the drag reduction can reach higher than 70% for both low- and high-viscosity slick water, and up to 68% for gel. It is also demonstrated that HVFR thickener exhibited multifunctional properties and can be freely transited between low- and high-viscosity slick water as well as gel by altering the concentration of HVFR. The cross-linked fracturing fluid based on HVFR displayed not only remarkable heat- and shear-resistance, but also proppant carrying capacity. The viscosity of the cross-linked fracturing fluid can be maintained at 120 mPa*s after shearing for 120 min at 120 oC and 170 s^(-1).

  • 1
• Performance evaluation of low density elastic sealing cement slurry to improve the sealing capacity between cement layers

  XING Xuesong

  Abstract: (881) HTML (0) PDF (0.00 ByteKB) (1854)

  Abstract:

  Abstract: Under the existing cementing slurry technology, ensuring the long-term stability of wellbore integrity is facing challenges, especially the conventional low-density slurry. After perforation, the integrity of cement stone is damaged more seriously, resulting in sealing failure, poor cementing quality between cement stone and casing and well wall, and channeling is easy to occur. In view of the above problems, it is preferred to use compound liquid fiber to improve the strength and toughness of cement paste, nano lightening agent to improve the settlement stability of cement slurry, and 10% res-1 elastic material is preferred to reduce the elastic modulus of cement paste and improve the deformation capacity of cement paste. The comprehensive performance evaluation of low-density elastic sealing cement slurry was carried out in the laboratory. The results show that the 1.5g/cm3 low-density elastic sealing cement slurry system has good rheology, adjustable thickening time of cement slurry, water loss less than 50ml, and linear expansion rate of 0.45%, which can effectively inhibit the generation of micro annulus and micro gap. Compared with ordinary low-density cement slurry, the permeability and elastic modulus of low-density elastic sealing cement slurry are reduced by 69.5% and 78.4% respectively, and the compressive strength and flexural strength are increased by 61% and 54% respectively, indicating that the cement slurry has good compactness, flexibility and elastic deformation ability. The evaluation of the sealing capacity of the cement sheath shows that under the conditions of alternating pressure range of 20mpa-40mpa and pressure rise and fall frequency of 5 times, the anti channeling strength in the simulated sealing is greater than 7 MPa/m2, which can effectively improve the long-term sealing capacity of the cement sheath and improve the cementing quality.

  • 1
• Research on the Mineralized Deposition of Nanoparticles and Its Application Exploration on the Improvement of Wellbore Stability

  Liu Zhendong

  Abstract: (806) HTML (0) PDF (0.00 ByteKB) (1859)

  Abstract:

  In the drilling of shale formation, the problem of wellbore stability is relatively prominent. Due to the special physical and chemical properties of shale, it is easy to absorb water and expand, resulting in the wellbore falling and collapsing, so it is necessary to reinforce the wellbore during drilling. In this paper,the process of biomineralization is simulated to study the self-assembly technology of nanoparticles. Based on the selection of cationic polymers and nanoparticles, this paper focused on the self-assembly deposition process of modified calcium carbonate and BPEI, as well as the structural analysis of the deposition layer. The experimental results displayed that modified nano-calcium carbonate could form a well deposition layer on the simulated well wall. In addition, this paper also explored the application of this technique on the improvement of wellbore stability which would provide a new strategy to solve the problem of wellbore instability.

  • 1
• Dynamic analysis and preparation of drag reduction and sand-carrying dual-functional polymer materials for shale fracturing

  ZHOU Cheng-yu

  Abstract: (818) HTML (0) PDF (0.00 ByteKB) (1808)

  Abstract:

  In order to solve the problems of large frictional resistance at the front end and low viscosity at the tail end of volumetric fracturing in shale reservoirs. The steric hindrance of twin tail monomers with different carbon chain lengths, mean square terminal distance and mean square displacement (MSD) of the polymer materials were studied based on molecular dynamics. The drag reducer LMA-AM-DiC12AM (LAD) was synthesized by micellar polymerization with Lauryl methlacrylate (LMA), Acrylamide (AM) and N,N-dodecyl acrylmaide (DiC12AM). The rheological properties, drag reduction and sand carrying properties of LAD solution were studied by rheometer and friction tester. The results show that DiC12AM monomer has small steric hindrance, the best chain flexibility of polymer materials molecules, the best ability to bind water molecules, and the great drag reduction potential. LAD has good shear stability (viscosity is 75mPa·s) and shear recovery performance. It can withstand a temperature of 60℃ at present. Its drag reduction rate reach 67.4%. The average sedimentation rate of 40/70 mesh ceramsite is 2.05×10-4 mm/s. The polymer materials agent has both drag reduction and sand carrying properties, which is basically consistent with the simulation results.

  • 1
• Application of the Nanoparticles Augmented Enhanced Oil Recovery

  ZHANG Xiaojun, GUO Jixiang

  Abstract: (1355) HTML (0) PDF (0.00 ByteKB) (1962)

  Abstract:

  Nanoparticles(NPs) are seen as potential solutions to overcome the challenges, such as low sweep efficiency, associated with these traditional EOR techniques. The application of nanoparticles augmented chemical EOR, gas EOR, and thermal EOR techniques in recent years have been summarized in this paper. The main principles, characteristics and research results of the nanoparticles augmented EOR process were introduced. Also, EOR challenges using NPs and the needed future research are highlighted. It provided foundation for the development of NPs augmented EOR technologies.

  • 1
• Development and performance evaluation of high temperature-resistant core-shell nano plugging agent used for oil-based drilling fluid

  Du Zhenghong, Peng Wu

  Abstract: (1265) HTML (0) PDF (0.00 ByteKB) (1801)

  Abstract:

  Nano pores and micro fractures are well developed in shale formation. However, the particle size of conventional plugging agent is large and it is difficult to plug pores and fractures in shale. A high temperature-resistant core-shell nano plugging agent CLG-NM was prepared with inorganic nano silica as the core and poly (styrene-butyl acrylate-acrylic acid) as the shell. The plugging agent was characterized by infrared spectroscopy, transmission electron microscopy, dynamic light scattering and thermogravimetry, and its plugging performance was evaluated by shale pressure transfer experiment. The results show that the particle size distribution of CLG-NM is 40 ~ 300 nm, the median particle size is 89.4 nm. CLG-NM maintains thermal stability below 372 ℃. Furthermore, CLG-NM has good compatibility with oil-based drilling fluid. After 3% CLG-NM was added into the oil-based drilling fluid of Weiye 28-7hf well, the rheological property of the drilling fluid changed slightly. The high temperature and high pressure filtration (aging at 180^oC for 16h) decreased from 3.1mL to 2.8mL, and the demulsification voltage kept higher than 700mV. Compared with KC-2 and PT-seal, CLG-NM has better plugging effect on the nano pores and fractures in shale.

  • 1
• Research on Polyelectrolyte Hydrophobic Associated Composite Suspension Stabilizer for Cementing

  ZHAO Qiyang, CHEN Xuewen

  Abstract: (997) HTML (0) PDF (0.00 ByteKB) (1950)

  Abstract:

  In deep and ultra-deep oil and gas resource cementing, due to the high temperature of the formation, some admixtures in the cement slurry fail at high temperatures, resulting in serious settlement of solid particles and loss of stability of the slurry, which increases the risk of channeling during cementing. In this work, a polyelectrolyte hydrophobic association composite suspension stabilizer P-AB with good temperature resistance was studied. The results of infrared spectroscopy, thermogravimetric analysis, particle size analysis and cryo-scanning electron microscopy show that: P-AB can form a unique grid structure through electrostatic interaction and hydrophobic association, which helps prevent cement slurry settlement and free water separation ; 1% P-AB aqueous solution can maintain a high viscosity at 40℃-150℃; after adding 0.5%-1% of P-AB to the cement slurry at a high temperature of 200℃, the density difference between the upper and lower sections of the cement stone will be less than 0.02 g/ cm3, the free liquid of the slurry is 0, and Zeta potential analysis shows that the addition of P-AB can improve the dispersion performance of the slurry. This technology is conducive to improving the cementing quality of deep and ultra-deep wells and reducing cementing risks.

  • 1
• Research Progress of Active Components in Crude Oil and Interaction on Influence of Emulsion Stability

  SUN Lin, Ren Zihan

  Abstract: (1054) HTML (0) PDF (0.00 ByteKB) (2041)

  Abstract:

  A large amount of emulsion is easily formed in the process of crude oil production due to the existence of active components, including asphaltene, resin, petroleum acid, and wax. Based on the composition and existing state of active components in crude oil, the influence mechanism of each active component on the emulsion stability was described. The interaction between active components and asphaltene with their influence on emulsion stability is summarized. Among the active components of crude oil, these are pointed out asphaltene is the main component of the interfacial film, and suitable resin with asphaltene can strengthen emulsifying effect. The results between carboxylic organic acid and asphaltene are various owing to different relative molecular weights, and the wax can enhance the strength of the interfacial film when they crystallize or interact with asphaltene. Meanwhile, current problems and future development directions are prospected.

  • 1
• Preparation and properties of gel dispersion for profile-controlling and flooding by aqueous RAFT polymerization

  YANG Ziteng, ZHANG Peng

  Abstract: (942) HTML (0) PDF (0.00 ByteKB) (1961)

  Abstract:

  Based on reversible addition fragmentation chain transfer (RAFT) aqueous polymerization, the micro/nano-polyacrylamide gel dispersions for profile-controlling and flooding were prepared to solve the problems of complicated preparation processes of common profile-controlling and flooding agents and the need to add organic solvents. A new water-soluble RAFT agent was synthesized, and then polyacrylamide gel dispersions were prepared by using the RAFT agent in water. The effects of reactant ratio, polymerization temperature, polymerization time and solid content on its properties were investigated. The rheological and viscoelastic properties of gel dispersions were tested. The temperature response, salinity responsiveness and pH responsiveness of gel dispersions were characterized. The results showed that the viscosity of gel dispersions decreased with the increase of temperature and decreased with the increase of pH value, but had little effect, and their viscosity was almost not affected by mineralization. Finally, the microstructure and particle size were characterized by atomic force microscope (AFM), scanning electron microscope (SEM) and nano particle analyzer. The results showed that the gel dispersion was irregular globular structure. The micron diameter of the gel dispersions was 0.92 ~ 6.13 μm and the diameter of the nanoparticles was 48 ~ 76 nm, which confirmed that the molecular scale of gel dispersions prepared by RAFT aqueous polymerization was micro/nano scale.

  • 1
• Preparation and performance evaluation of polymer microsphere as drilling fluid filtrate additive

  Liu Yun

  Abstract: (1043) HTML (0) PDF (0.00 ByteKB) (2102)

  Abstract:

  As the existing filtrate reducers often have an unsatisfied performance in the high temperature and high salinity environment, a polymer microsphere is synthesized by inverse emulsion polymerization of water-soluble monomers (sodium p-styrene sulfonate, 2-acrylamide-2-methylpropanesulfonic acid and acrylamide) using liquid paraffin as the continuous phase, Span 80 and Tween 60 as emulsifier. Infrared spectroscopy, thermogravimetric analysis, scanning electron microscope and laser particle size analyzer are used to characterize the product. Then the swelling performance, salt resistance, aging performance, temperature resistance and plugging experiments also are studied. It is shown that microspheres display a spherical morphology with a particle size of 2.82-10.26 μm, and begin to decompose at 270 ℃. It is found that the final expansion ratio in deionized water approaches to 500%. In addition, microspheres exhibit a good fluid loss reduction performance in high salinity and high temperature conditions, and have anti-aging property. After plugging experiments, the polymer microspheres are observed in macropore of core slice, where plug performance is achieved by polymer microspheres.

  • 1
• Preparation and analysis of acrylate- methacrylic acid copolymer emulsion reversed demulsifier

  ZHANG Tao

  Abstract: (1074) HTML (0) PDF (0.00 ByteKB) (2299)

  Abstract:

  Requirements for sewage treatment chemicals are very high due to the limited sewage treatment equipment and short residence time in offshore oilfield. Thus, it is necessary to develop a high-efficient reversed demulsifier to improve the separation efficient of oil and water. In this work, acrylate-methacrylic acid copolymer emulsion reversed demulsifier (EMASA) was synthesized via emulsion polymerization method by using EA, MAA and SA as precursors. The structure and thermal properties of synthsized copolymer were characterized using FT-IR?, 1HNMR and DSC. The oil removal rates of synthesized copolymers were further investigated based on the water from the offshore oilfield A platform(water type is sodium bicarbonate). Results suggests that the oil removal rate of EMASA was 96.5% under a filling concentration of 30 mg/L, and the value further increased to 98.9% at the assistance of the flocculant,ECHA. Pilot scale test of the property of EMASA was further carried out on platform A. It was found that the OIW at the outlet of the oil system decreased from 255.75mg/L to 197.58mg/L under a EMASA filling concentration of 30mg/L, and the oil removal rate of the oil system increased from 94.89% to 96.05%. The mechanism of the role of EMASA was also clarified based on the results of dynamic light scattering, interfacial tension and expansion modulus.

  • 1
• Experimental investigation of zeolitic imidazolate framework nanoparticles for enhanced oil recovery

  HE Xuan, LIU Yuetian

  Abstract: (919) HTML (0) PDF (0.00 ByteKB) (1903)

  Abstract:

  Nanomaterials have attracted extensive attention in the study of enhanced oil recovery due to their unique physical and chemical properties. However, there are still some shortcomings such as poor dispersion, easy agglomeration and low recovery rate. It is very important to synthesize new nanoparticles and apply them to the research of enhanced oil recovery. In this paper, ZIF-8 nanoparticles were prepared for EOR applications and their microstructures were characterized by X-ray diffraction and field emission scanning electron microscopy. In order to prepare the nanofluids, the nanoparticles were dispersed in brines with different concentrations, which were characterized through analyzing their stability. Then the prepared nanofluids were used to measure the interfacial tension and contact angle between crude oil and water on the surface of sandstones. Finally, the core displacement experiments were carried out. The results show that the average diameter of the prepared ZIF-8 nanoparticles is 65.8nm, and the phase state is single without impurities. When the mass fraction is not higher than 0.03%, the dispersion in water is excellent, and the absolute value of Zeta potential is about 30mV, which has a high stability. After adding 0.03% ZIF-8 nanoparticles in simulated formation water and low salinity water, the interfacial tension values decreased to 4.662 and 3.965mN/m, respectively, which decreased by 75.76% and 73.27% compared with that without adding. The contact angle decreases from 114°, 109° to 78° and 73°, respectively, and the rock surface towards to more water-wet, which is more conducive to the peeling of oil film. Thus, the recovery was increased by 8.25% and 10.71% with 0.03% ZIF-8 nanofluid under the high and low salinity conditions, respectively.

  • 1
• Anti-blocking system in water injection process of low permeability loose sandstone reservoir with high clay

  Liang Yukai, Yu Xiaocong

  Abstract: (833) HTML (0) PDF (0.00 ByteKB) (1709)

  Abstract:

  Aiming at the problem of high injection pressure caused by particle migration blocking the reservoir pore throat in the process of water injection in high clay loose and low permeability sandstone reservoir, a neutral gradient anti plugging system was optimized through laboratory experiments. The low-speed gradient anti plugging system is 0.5% KCl clay stabilizer, and the high-speed gradient anti plugging system is 0.2% KCl + 0.3% organic cationic clay stabilizer. The anti-swelling property of gradient anti plugging system and the changes of core pressure and permeability during displacement were investigated. The results showed that the anti-swelling rate of the system was more than 91%. Compared with the blank production water displacement, at low speed, after being treated by the anti-plugging system, the pressure growth multiple was reduced from 5.41 to 2.03, and the permeability retention rate was increased from 18.49% to 49.15%; At high speed, after being treated by the anti-plugging system, the core permeability gradually recovered. When 8PV was replaced by production water, the permeability retention rate increased from 10.56% to 91.58%, and the pressure growth multiple decreased from 9.47 to 3.28. The plugging prevention system is neutral, which provides a strong support for the advanced green water injection and efficient development of low permeability reservoirs.

  • 1
• Evaluation and application of polymer microsphere / surfactant composite profile control and flooding system

  WU Tianjiang

  Abstract: (1493) HTML (0) PDF (0.00 ByteKB) (1848)

  Abstract:

  According to the characteristics of Changqing Low Permeability Reservoir, polymer microsphere / surfactant composite profile control and oil recovery technology is proposed. The initial particle size of polymer microspheres is generally 50-300nm, and it has hydration expansion characteristics with expansion ratio of 5-10 times. The aggregation characteristics of microspheres during hydration and expansion were observed by SEM, and the particle size distribution was Gaussian normal distribution. The most economical concentration of surfactant is 0.3%. The results show that the viscosity of the mixture increases after adding surfactant to polymer microspheres, and the dispersed phase particles of microspheres shield the interfacial activity and micelle formation ability of surfactant, which results in the decrease of interfacial tension, which is not conducive to surfactant flooding. When the mass concentration of microspheres is greater than 0.4%, the plugging rate is more than 80%. The best injection mode of polymer microspheres and surfactant is slug injection with volume ratio of 1:1. The application effect of this technology in Ansai Oilfield is good, and the cumulative oil increase is 3576t, showing good technical adaptability.

  • 1
• Synthesis and Properties of a MultipStudy on Synthesis and properties of reinforced materials for oil well cement

  Liu Xuepeng

  Abstract: (810) HTML (0) PDF (0.00 ByteKB) (1690)

  Abstract:

  In this paper, a heterogeneous particle was synthesized from diphenylmethane diisocyanate (MDI), polyepoxypropane glycol, silicate aqueous solution and heavy calcium carbonate, which was used to reduce the elastic modulus of oil well cement. The first phase of multiphase particles is a porous continuous phase, and the second phase is basically spherical; In the multiphase particles, the second phase is embedded in the holes of the first phase, and the spherical second phase contains 18 ~ 20% Si element. The experimental results show that the cement stone with multiphase particles has lower elastic modulus than that of neat paste cement stone, but the strength does not decrease; Multiphase particles have little effect on the thickening time and rheology of cement slurry; The spherical structure at the interface of multiphase particles contains a large number of silicon hydroxyl groups, which participate or partially participate in the hydration of cement, forming a permeable structure at the interface to ensure the continuity of cement hydration structure.

  • 1
• Foam Properties and CO₂/N₂ Response Properties of Anionic Surfactant/ Tertiary Amine Compound Foam

  LIU Dong-Mei, SUN Shuang-Qing

  Abstract: (941) HTML (0) PDF (0.00 ByteKB) (1906)

  Abstract:

  In this paper, the foam performance of sodium dodecyl sulfate (SLS), sodium dodecyl sulfonate (SDS), sodium dodecylbenzene sulfonate (SDBS) and N-dodecyl-N, N-dimethyl tertiary amine (C12A) equimolar compound solution were studied through foam experiments, and the influence of inorganic salt and oil relative to the foam performance of the compound system. In addition, for the SLS/C12A compound system and SDS/C12A compound system with better foam performance, CO2 response defoaming and N2 heating recovery re-foaming and defoaming experiments were carried out. The research results show that the SLS/C12A compound system has the best foam stability and strong salt tolerance. The anti-oil effect of the SDS/C12A compound system is remarkable, and the two compound systems both show good CO2 responsiveness and reversibility. According to the change of the solution and the change of surface tension after defoaming, the response mechanism is inferred that the protonated C12A and anionic surfactants are electrostatically attracted to form a complex, which precipitates out of the solution, which reduces the surface activity of the solution and accelerates the breaking of the foam.

  • 1
• Research progress and application prospects of drilling fluid additives in intelligent water-based drilling fluid chemical system

  Shen Haokun

  Abstract: (1288) HTML (0) PDF (0.00 ByteKB) (1941)

  Abstract:

  Traditional water-based drilling fluid has some disadvantages, such as tedious process of drilling fluid configuration, poor pertinence and weak adaptive ability. Intelligent water-based drilling fluid has become a new research direction in the field of oilfield chemistry because of its better pertinence and universality, and can greatly reduce the degree of manual intervention. Through literature analysis, the mechanism and research progress of intelligent materials such as intelligent water-based drilling fluid additive in water-based drilling fluid are described. According to the characteristics of different intelligent drilling fluid additives, the feasibility of intelligent materials in water-based drilling fluid is discussed, and the research ideas, methods and application prospects of intelligent drilling fluid additives in intelligent drilling fluid system are prospected.

  • 1
• The Research and Oilfield Trial of Horizontal Well Selective Water Shutoff Agent in Glutenite Oil Reservoir

  Li Yikun

  Abstract: (1016) HTML (0) PDF (0.00 ByteKB) (1864)

  Abstract:

  The Kunbei glutenite reservoir has thick layer and strong heterogeneity in plane, interlayer and intralayer. In the early stage of development, the horizontal well production yield decreases and water cut rises rapidly. Horizontal wells are in urgent need of water control. Based on the characteristics of Kunbei reservoir and production, Acrylamide (AM)-2-acrylamido-2-methylpropanesulfonic acid (AMPS)-dimethyldiallylammonium chloride (DMDAAC) terpolymer selective water shutoff agent for horizontal wells was synthesized. The injection performance of water shutoff agent was investigated by rheological mechanics experiment, and the selectivity of water shutoff agent was investigated by core plugging simulation experiment. The core experiment shows that the injection pressure is increased by 6.06 times after water plugging, the water flooding plugging rate is 83.5%, and the oil displacement plugging rate is 20%, which has remarkable oil-water selectivity.On the basis of laboratory experiment and well performance, the oilfield trials of water shutoff for 6 horizontal wells have been carried out in Kunbei Oilfield. The remarkable effect of increasing oil and reducing water has been gained.

  • 1
• Application of New Low-damage and High-performance Micro-foam Drilling Fluid in Coalbed Methane Wells in Eastern Yunnan

  Ma Tengfei, Zhou Yu

  Abstract: (1233) HTML (0) PDF (0.00 ByteKB) (1869)

  Abstract:

  The third member of Feixianguan Formation and the first member of Feixianguan Formation in eastern Yunnan are easily unstable formations. In order to protect coal bed reservoirs, new low-damage high-performance micro-foam drilling fluid technology is designed and applied. The developed foaming agent LHPF-1 was compounded with foaming agent BS-12 and tackifier XC, and the response surface optimization experiment was used to analyze the influence of the interaction between the three treatment agents on the foam composite index Fq. On this basis, fluid loss agents and inhibitors are optimized, and the final microfoam drilling fluid formula is determined to be: 0.25%LHPF-1+0.25%BS -12+0.25%XC+1%SPNH+1%NH4HPAN+0.2%KPAM. The research results show that the density of the drilling fluid can be reduced to 0.49g/cm3, the foaming volume can reach 420mL, the half-life of the foam can reach more than 2000min, the thickness of the foam liquid film can reach 50% of the foam size, and the coal core plugging rate and permeability The recovery value is above 90%, and it is resistant to 7% of debris and coal pollution. The drilling fluid was applied on-site in the second opening section of Well LC-C7-2D in the Laochang exploration area in eastern Yunnan. The pure drilling time was 4 days without any complicated downhole accidents. The average caliper expansion rate for the whole section was 5.9% , The fluid loss is less than 5mL.

  • 1
• Study on the low-damage slick water fracturing fluid of Baikouquan Formation in Mahu 1# well area

  ZHANG Ying, YU Weichu

  Abstract: (1206) HTML (0) PDF (0.00 ByteKB) (1855)

  Abstract:

  Baikouquan formation in Mahu 1# well area is a typical tight oil reservoir with low porosity and low permeability, which large-scale hydraulic fracturing is need to increase production. However, there are three major problems. First, the fracturing fluid has poor drag reduction effect and is harmful to the reservoir. Second, water resources are scarce and oil field sewage treatment is difficult. Third, the recovery rate needs to be improved because of the distribution of residual oil between the joints. So, the JHFR drag reduction agent was synthesized which is low-damage. And then, JH slick water fracturing fluid with low damage was constructed. JH mainly composed of 0.1% JHFR drag reduction agent and 0.2% JHFR multifunctional additives. The fluid is characterized by instant dissolution (15 s), high efficiency drag reduction (76.9%), low oil-water interfacial tension (0.89 mN/m), and good anti-swelling effect (CST ratio 0.92)., and other characteristic. The system has good compatibility with formation water and backflow fluid in the Mahu 1# well area, and the damage degree to core permeability is low. So, it is suitable for large-scale continuous fracturing in the Mahu 1# well area.

  • 1
• Study and Field Application of Organic Boron/Zirconium Composite Linear Gel Fracturing FluidWAN Qingshan_^1*, BAI Lei_¹,LI Bin_²,CHEN Liyan_¹,ZHAKE Jian_¹

  Wan Qingshan

  Abstract: (1072) HTML (0) PDF (0.00 ByteKB) (1885)

  Abstract:

  Based on the formation principle of partially hydrolyzed polyacrylamide (HPAM) and polyhydroxyl alcohol weak gel, the crosslinking agent FHBZ-1 was used to prepare the crosslinking gel with HPAM and polyhydroxyl alcohol, and it was used as the fracturing fluid of LG-2 composite linear gel. Zirconium crosslinking agent was prepared by mass ratio of Zirconium chloride, lactic acid, propyl alcohol, triethanolamine of 6:5:1:24 in 75℃ water bath for 2h. Boron cross-linking agent was prepared by mass ratio of Borax, mannitol, water/glycerol (volume ratio 3:1) Mixed solvent, NaOH of 18:16:6:2, pH value: about 10, reaction temperature: 80℃, reaction time 5h.The organic boron crosslinking agent and the organic zirconium crosslinking agent were mixed according to the volume ratio of 1:2 to form FHBZ-1.The crosslinking, temperature resistance and shear resistance of LG-2 linear gel fracturing fluid system were evaluated respectively.Experiment from LG - 2 linear gel fracturing fluid optimization ratio of 0.3% (wt) HPAM + 0.5% (wt) CPA - 1 + 1.2 (v) % FHBZ - 1 + 0.05% (v) ZP + 0.3% + 0.05% APS NW (v).The final viscosity of 448mPa?s was obtained by shear at a constant speed of 170s^-1 for 90min at 130℃, indicating its good temperature and shear resistance.The performance of LG-2 linear glue fracturing fluid was evaluated at 60 and 90℃. The viscosity of LG-2 linear glue fracturing fluid was small, and the amount of residue was low, which was about 16mg/L and 12mg/L, respectively.Field test of WY-8 shale gas well verified that LG-2 linear glue fracturing fluid system has excellent performance of seam making and sand carrying.

  • 1
• Research on Mechanism of Pickering Microemulsion Control Swelling of Clay in Heavy Oil Reservoir

  Guo MIngzhe

  Abstract: (1022) HTML (0) PDF (0.00 ByteKB) (1712)

  Abstract:

  Inhibition of clay expansion is a premise of effective thermal recovery in water sensitive heavy oil reservoir, however, a quantitative description of mechanism that stabilizer inhibits clay expansion, which is remaining unclear. First, a Pickering microemulsion applied to control clay swelling was proposed, besides mechanism of expansion inhibition Pickering microemulsion was analyzed by combination of Fick"s law and Langmuir theory of adsorption. Then, effect of Pickering microemulsion formed by the compounded mixtures of hydrophobic nano SiO2 and lauryl three methyl ammonium bromide (DTAB) on water surface tension was tested, and the suppression bentonite’s swelling rate of the Pickering microemulsion was also measured, which obtained optimum formulation. Finally, the dynamic anti-swelling effect of the Pickering microemulsion was studied by slug displacement experiments through best formula. The quantitative analysis shows that it is feasible to prevent clay swelling by surface adsorption. When the ratio of nano-SiO2 to DTAB is 1:2 and the concentration is 0.6wt%, the best inhibition effect of bentonite was obtained. The best slug injection volume is 0.2PV in test. with unceasingly increasing microemulsion injection volume, the anti-swelling effect was more obvious. But the rate of increase of water cut also was accelerated, which indicated that the clay swelling should be properly controlled in heavy oil reservoirs with high permeability.

  • 1
• water-soluble resin-based cementing fluid system

  HE Yingzhuang, YAN Siming

  Abstract: (885) HTML (0) PDF (0.00 ByteKB) (1921)

  Abstract:

  In view of the problems of gas channeling and wellhead pressure caused by high pressure and fracturing in the development of oil and gas fields, water-soluble resin was used as the main cementitious materials and a resin-based cementing fluid system at low and medium temperature was prepared. The engineering performance, anti-channeling ability, mechanical property, temperature resistance and curing kinetics of the system were studied. The results show that the density of the resin system can be adjusted to 1.20~1.80g/cm³ through the combination of weighting agent and suspending agent, and it has good flowing ability. The thickening time can be adjusted from 60 to 410 min by changing the dosage of curing agent and accelerator between 60℃ and 90℃. When the displacement efficiency is 91.5%, the consolidation strength of cured resin is 3.01 MPa, the interface breakthrough pressure is more than 12 MPa, which is much higher than that of conventional cement stone under similar displacement efficiency. The compressive strength of cured resin is above 50MPa after curing at 90℃ for 24h, and the elastic recovery rate is more than 85% after six cycles of alternating stress loading, which is better than that of ordinary set cement. The TG analysis demonstrates that initial decomposition temperature of cured resin is 398℃, which indicates that the resin-based cementing fluid has good temperature resistance. The curing kinetics equations of S-HR/CA-1and S-HR/DCY systems, and the relationship between curing degree and curing time was determined. The resin cementing fluid has consolidation strength and strong deformation recovery ability at the cementing interface, which is conducive to ensuring the long-term integrity and sealing performance of cementing material, and preventing fluid channeling of oil and gas wells. The study of curing kinetics provides a theoretical reference for the research and application of this kind of resin working fluid system.

  • 1
• Demulsification Mechanism of quartz sand on heavy oil emulsion

  ZHANG Dianchen, ZHANG Shijian

  Abstract: (877) HTML (0) PDF (0.00 ByteKB) (1960)

  Abstract:

  Because the heavy oil emulsion is opaque and it is impossible to intuitively understand the influence of sand particles on the stability of heavy oil emulsions, some scholars have detected the asphaltenes adsorbed on the surface of mineral particles by Fourier transform infrared spectroscopy. It is speculated that these particles destroy the strength of oil/water interfacial film due to the adsorption of asphaltenes on the oil/water interfacial film and promote the aggregation of water droplets,Sso as to realize demulsification and stratification of heavy oil emulsion.SHowever, this understanding cannot explain some phenomena in our experiment. In this paper, experiments such as bottle experiment, rheology test and wettability test are carried out, and the influence mechanism of quartz sand on the stability of heavy oil emulsion is obtained: when the sand particle size is small and the water droplet particle size is large, the phenomenon of water droplets completely wetting and wrapping the sand particles will occur, the proportion of water droplets wrapping the sand particles will increase, and the settlement speed will accelerate,SThis is the main reason for the demulsification and stratification of heavy oil emulsion by sand, and this understanding is also verified by the sedimentation experiment of sand in white oil.

  • 1
• Synthesis and evaluation of a new small molecular clay stabilizer ZWS-1with high temperature resistant

  SHEN Huibing, WU Pingping

  Abstract: (1094) HTML (0) PDF (0.00 ByteKB) (1960)

  Abstract:

  In view of the problems such as poor washing resistance of inorganic salt clay stabilizer, easy adsorption and blockage of pore channel and poor temperature resistance of polymer clay stabilizer, it is urgent to develop a new type of small molecule clay stabilizer for high temperature and low permeability reservoir. In this work, high temperature resistant clay stabilizer ZWS-1 was synthesized with trimethylamine and γ-chloropropyltriethoxysilane. The optimized weight concentration of ZWS-1 applied for clay stabilization was 1.5%. A synergistic effect was observed on 5% ZWS-1 and 4% KCl, which exhibited a decrement of clay swelling of 98.3%, and the washing resistance of 91.4% at 150 ℃. The characterization results indicate that ZWS-1 leads to the agglomeration of clay particles and increase the stability of clay. Fourier transform infrared spectroscopy (FTIR) results reveal that ZWS-1 reacts with hydroxyl groups of the clay surface, which indicates that the presence of chemical bond between ZWS-1 and clay minerals.

  • 1
• Research on Imbibition of Surfactant to Improve the Production Characteristics of Crude Oil in Matrix-fracture Dual Media

  WANG Xingkun, DAI Caili

  Abstract: (1132) HTML (0) PDF (0.00 ByteKB) (1948)

  Abstract:

  Surfactant imbibition is an important means to improve the production of tight oil matrix crude oil and the characteristics of surfactant imbibition in the tight oil matrix-fracture model to improve crude oil production was studied in this paper. First, 0.05 wt% of ASB is preferred as a surfactant for imbibition by spontaneous imbibition, measuring interfacial tension, and wettability. Furthermore, through the matrix-fracture core model and the microfluidic model, the effects of the fracture tortuosity and the velocity in the fracture on the dynamic imbibition of the near-fracture matrix to improve the production characteristics of crude oil were studied respectively. The results show that the degree of crude oil recovery by dynamic imbibition of the near-fracture matrix increases with the increase in the tortuosity of the model, that is, the higher the fracture complexity, the higher the degree of dynamic imbibition recovery; the faster the flow velocity in the fracture, the oil-water interface in the capillary the faster the migration rate, that is, the faster the imbibition rate, and the migration rate of the oil-water interface and the flow velocity in the fracture conform to the law of quadratic function as a whole. Also besides, the effects of the action depth and concentration of surfactant on the spontaneous imbibition of the deep matrix to improve the production characteristics of crude oil were studied through static imbibition experiments. The results show that the deeper the surfactant action depth, the lower production of crude oil per unit volume. When the surfactant concentration is high, the variation law of the degree of spontaneous imbibition production is consistent with the interfacial tension as the main control parameter of the capillary force is the interfacial tension. When the surfactant concentration is low, the main controlling parameter of the capillary force is the wettability of the rock surface. At this time, the variation law of the degree of spontaneous imbibition and production is opposite to the interfacial tension.

  • 1
• Efficient preparation of nano starch particles and its effect on the performance of drilling fluid

  Ma Peng, Zhang Lei

  Abstract: (1136) HTML (0) PDF (0.00 ByteKB) (2143)

  Abstract:

  In order to meet the requirements of environmental protection and efficient drilling of unconventional shale reservoirs, it is necessary to develop a new type of drilling fluid system with excellent performance and environmental friendliness. In this paper, ultrasonic treatment and precipitation method are combined to solve the problem. First, ultrasonic treatment is used to reduce the viscosity of starch solution with a high concentration of 5%. Thus, the precipitation method is used to prepare nano-starch particles under the condition of high concentration starch solution. After preparation by the method, the average size of the nano starch particles is as small as 30nm, and the particle size is mainly concentrated in 20-50nm with a relatively uniform distribution. The salt resistance of the nano starch particles is 20g/L NaCl at 150°C. After adding 1.0% nano starch particles to the base slurry, the apparent viscosity, plastic viscosity, dynamic shear force and fluid loss are 22.0 mPa.s, 14.5 mPa.s, 11.5 Pa and 9.3 mL, respectively. After aged at 150℃, the apparent viscosity, plastic viscosity, dynamic shear force and fluid loss after 16 hours are 21.1 mPa.s, 14.0 mPa.s, 10.8 Pa and 10.0 mL, respectively. More importantly, nano-starch particles and bentonite can form a network structure, which can increase the apparent viscosity, plastic viscosity, and shearing force of the drilling fluid, and decrease fluid loss, and it can still maintain excellent performance after aging under high temperature. The combination of ultrasonic treatment and sedimentation method is easy to be operated, low cost, easy to be promoted and applied. The formed technology can provide an important technical support for the development of a new type of nano-drilling fluid system.

  • 1

• Research of hydrogen sulfide treatment and efficiency enhancement technology in offshore oil fields

  WANG Dawei, ZHANG Shilun, JING Bo, HUANG Bo

  Abstract: (67) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  In response to the hydrogen sulfide production issue in the offshore S oilfield, while also considering the enhancement of recovery efficiency, a composite solution approach of "inhibition-activation-enhancement" has been proposed. Based on the principles of molecular ecology and genomic proteomics, a composite system was developed through community analysis, strain screening, agent optimization, and efficacy evaluation. This system is capable of both inhibiting hydrogen sulfide-producing bacteria and activating microbial functions, effectively suppressing the hydrogen sulfide-producing bacteria in the oilfield system while achieving the goal of enhanced microbial oil recovery. A field trial for hydrogen sulfide treatment was conducted at well A07 in the S oilfield in August 2024. The H2S concentration decreased from 50ppm to 9ppm, the SRP concentration decreased from 103 to 10 per ml, a reduction of two orders of magnitude, and the NRB concentration increased from 103 to 105 per ml, an increase of two orders of magnitude, indicating a significant activation effect of the agent on NRB. As of June 15, 2025, the water content in the benefiting well group decreased by 3.1%, with a phase increase in oil production of 6541 cubic meters, and the effective period has reached 6 months and continues to show results, providing a new approach for hydrogen sulfide treatment and enhanced recovery in offshore oilfields.

  • 1
• Profile Reversal Law and Microscopic Oil Displacement Mechanism of Chemical Flooding for Heavy Oil in Suizhong 36-1 Oilfield

  WU Zhanqi, XIE Kun, LIU Yanchun, XU Fanyue, CAO Weijia, BAI Jie

  Abstract: (81) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  In the middle and later stages of chemical flooding in heavy oil reservoirs in Bohai Oilfield, profile inversion is prone to occur. This further leads to issues such as intensified intra-layer contradictions, severe ineffective circulation of oil displacement agents and rapid increase in water cut in some production wells, reducing the effectiveness of increasing oil and decreasing water of oil displacement agents. In order to study the profile reversal law and microscopic oil displacement mechanism of chemical flooding in heterogeneous heavy oil reservoirs, the study first conducted intra-layer "separate injection and separate production" heterogeneous core displacement experiments, clarifying the effect of different chemical flooding systems on enhancing oil recovery and the changes in injection and production profiles. Based on this, microscopic visualization experiments were carried out to clarify the distribution and occurrence status of remaining oil in chemical flooding, and further explore the microscopic oil displacement mechanism of different chemical flooding systems. The results indicate that the increase in oil recovery by different chemical flooding systems is in the following order: functional polymer>"high molecular weight" polymer>viscosity reducer. In the process of chemical flooding in heavy oil reservoirs, the dynamic changes in the injection and production profiles are influenced by both oil-water interfacial tension (IFT) and oil-water flowability ratio. Reducing the cluster-like remaining oil in porous media is a crucial mechanism for EOR of heavy oil chemical flooding. Viscosity reducers can reduce IFT and to some extent reduce cluster remaining oil, but the emulsion is prone to remain in the pores and form isolated-island-like remaining oil. “High molecular weight” polymer can increase the viscosity of water phase and expand swept volume. However, due to the poor effect to reduce the IFT, it is difficult to displace oil in small pores, resulting in a large amount of column-like remaining oil. Functional polymer has the functions of thickening the water phase, retaining and increasing resistance in high-permeability layers, and emulsifying capture and carrying. It can effectively increase the flowability of oil, expand swept volume. After water flooding, the oil recovery can be increased by more than 30%.

  • 1
• Development and Evaluation of a Gas Wettability Alteration Fracturing Fluid for Permeability-Enhancing and Flowback-Promoting Applications

  WEI Jun, LIU Bofeng, YANG Hongrui, LIU Peng, HE Hualei

  Abstract: (176) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To address the technical challenge of water lock damage caused by fracturing fluid retention during the fracturing development of tight gas reservoirs, which restricts gas seepage and flowback efficiency, this study aims to develop a gas wettability reversal fracturing fluid system with both permeability enhancement and flowback promotion functions, and to provide an effective technical approach for mitigating water lock damage in tight gas reservoirs through systematic evaluation of its key performance indicators. The study first screened nine gas wetting agents using surface tension and core contact angle as evaluation indicators, identifying two high-performance systems, HB-2 and YS-2. Further screening through concentration optimization, high temperature aging, and salt resistance evaluation confirmed that HB-2 at a concentration of 0.3 wt% exhibited the best overall performance, withstanding temperatures up to 120°C and adapting to high salinity formation water environments.The gas-wetting fracturing fluid system built around 0.3 wt% HB-2 exhibits good compatibility with conventional additives. Its viscoelasticity and rheological properties meet the requirements of fracturing operations. Under the condition of 95°C, the system can be completely broken within 60 min. The viscosity of the broken gel fluid is lower than 3 mPa·s, and the residue content is lower than 50 mg/L. All indicators meet the industry standard (SY/T 6376-2008). Laboratory experiment results confirm that this system provides excellent formation damage control. Wettability tests show that after treatment with this system, the water phase contact angle of the core increases from a hydrophilic state (< 90°) to above 116°, achieving a wettability reversal of the reservoir rock from strongly hydrophilic to strongly hydrophobic (gas-wetting). Core displacement tests and nuclear magnetic resonance analysis indicate that compared with conventional fracturing fluid, this system can effectively mitigate the problems of pore reduction and permeability decline caused by solid phase retention, achieving a higher permeability retention rate for high-permeability cores and causing less damage to the reservoir pore structure.This study successfully developed a gas wettability reversal fracturing fluid system based on 0.3 weight percentage HB-2. The system not only exhibits excellent overall performance that meets industry standards, but more importantly, it can significantly alter the wettability of reservoir rock surfaces, achieving a reversal from strongly hydrophilic to strongly hydrophobic. It demonstrates favorable formation damage control effectiveness and permeability-increasing and flowback-promoting potential, providing an effective technical means for the efficient development of tight gas reservoirs.

  • 1
• The Law of Fiber Fracturing Fluid Carrying and Transporting Coal Powder

  ZHAO Haifeng, LIANG Zhifei, YANG Shiying, LIN Hongliang, ZHU Qi

  Abstract: (51) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  During the CBM (Coal Bed Methane) drainage and development of pulverized coal seam blocks, the coal matrix is relatively fragmented, which easilyleads to the settlement and accumulation of coal fines during the fracturing process. Conventional fracturing fluids are difficult to effectively control the production of coal fines, and may also cause adverse consequences such as fracture plugging, resulting in fracturing failure. To address the above issues, this paper proposes a technical scheme of using fiber fracturing fluid for fracturing in pulverized coal seams. Fiber fracturing fluid has a good carrying capacity, which can increase the placement distance of proppants and simultaneously distribute coal fines evenly in fractures, thus ensuring the fracture conductivity. Firstly, a coal fine particle settlement experiment was carried out to evaluate the coal fine capture effect of fibers. Then, considering the mechanical properties of fibers, models of fracturing fluid hydrodynamics, particle kinematics and fiber dynamics were established to study the multiphase flow laws of fiber fracturing fluid, coal fines and proppant particles, and reveal the movement law of fiber intercepting coal fines. Finally, the effects of fiber concentration, sand placement concentration and injection rate of fracturing fluid on the control of coal fine migration were simulated. Research findings indicate that analyzing the resistance changes of coal powder aggregates with different particle sizes in guar gum fracturing fluids has determined the optimal fiber addition range to be 0.08%–0.12%. This study provides reference for coal seam fracturing and other formations such as water-sensitive shale fracturing.

  • 1
• Laboratory Experiments on Improving Recovery of Jimsar Shale Oil by Chemical Viscosity Reduction Combined with CO? Flooding

  Wang He, Zhang Lei, Feng Yue, Huo Yingming

  Abstract: (234) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  The shale oil reservoir of the Lucaogou Formation in the Jimsar Sag currently faces bottlenecks such as rapid natural energy decline and high crude oil viscosity. While gas injection has emerged as the primary approach for shale oil exploitation, there is an urgent need for chemical viscosity reduction measures tailored to the reservoir conditions of the Jimsar Sag, given the high viscosity characteristics of its shale oil. This study investigates a compound flooding technology system combining a chemical agent system with CO? to provide an experimental basis for enhanced oil recovery in shale reservoirs. First, the physical properties of the Jimsar Sag shale oil reservoir were characterized through comprehensive analyses of porosity, permeability, pore-throat structure, and sensitivity evaluation, thereby delineating the reservoir features of the Jimsar shale oil play. Under formation temperature conditions, a ternary compound viscosity reduction system comprising anionic, nonionic, and amphoteric surfactants compatible with CO? was screened and its reservoir adaptability verified. On this basis, core huff-n-puff experiments were conducted to evaluate the improvement in oil recovery, and microscopic visualization experiments were performed to elucidate the compound flooding mechanism. The results indicate that the pores of the Jimsar shale reservoir are dominated by nanopores ranging from 10 to 100 nm, with relatively few micropores and a complex pore-throat network structure. The strong capillary resistance generated by the unimodal nanopore system is identified as the core factor restricting oil recovery. Optimized for formation conditions, the screened ternary compound system (2% sodium cetyl sulfate + 0.5% BS-12 + 1.2% NP-10) exhibits excellent performance, achieving a viscosity reduction rate of up to 96.24% and demonstrating effective adaptability to reservoir conditions. Under a pressure of 40 MPa, the combined CO?–chemical agent huff-n-puff process yields the most significant effect, with a cumulative oil recovery of 39.14%, representing an increase of 11.64% compared with pure CO? huff-n-puff.

  • 1
• Effects of Near-Wellbore Perforation and Long-Distance Shear on Polymer Flooding Performance in High-Temperature, High-Salinity Reservoirs and Critical Control Factors

  ZHAO Fangjian, ZHANG Lei, SHI Jing, PAN Binlin, CHEN Xingfeng, LI Haonan, ZHANG Xinmin

  Abstract: (53) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Polymer viscosity is severely degraded in high-temperature, high-salinity (HTHS) reservoir environments and under shear conditions. However, the impact of polymer viscosity on oil recovery after shear through perforations or over long distances remains unclear. This study investigates the performance variations and governing mechanisms of three polymers—ultra-high molecular weight partially hydrolyzed polyacrylamide (HPAM), a temperature- and salinity-resistant ultra-high molecular weight polymer (NKSP), and an ultra-high temperature-resistant low-hydrolysis polymer (PSVP)—under HTHS conditions and perforation/long-distance shear. The results indicate that the shear resistance follows the order: PSVP > NKSP > HPAM. Perforation shear significantly reduces the molecular weight and viscosity of HPAM and NKSP, whereas long-distance shear has a minor effect on the viscosity loss rate and molecular weight of the three polymers. The ability to establish high flow resistance follows the order: NKSP > PSVP > HPAM, with corresponding enhanced oil recovery (EOR) values of 12.44%, 11.18%, and 7.89%, respectively. Further evaluation of the effects of different ions on NKSP reveals that, under anaerobic conditions at 10 mg/L, both the EOR and viscosity retention rate follow the trend: S²?/Fe²? > S²? > Fe²?. Conversely, higher Ca²? concentrations lead to lower EOR and viscosity retention rates, exhibiting a nonlinear relationship with polymer viscosity. At elevated temperatures, long-distance shear exerts a significant and continuous impact on the polymer''s viscosity loss rate and EOR. Appropriately increasing the polymer concentration helps maintain the viscosity retention rate after shear, and a nonlinear relationship is observed between post-shear viscosity and EOR. This study clarifies the key control mechanisms of long-distance polymer shear in HTHS reservoirs, providing a theoretical basis for optimizing injection allocation in field applications.

  • 1
• Research Progress on Constant Rheology Modifiers for Water-Based Drilling Fluids

  GENG Tie, YANG Jie, CHEN Butao, CUI Ce, YIN Hongyao, FENG Yujun

  Abstract: (64) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  With the exploration and development of deepwater/ultra-deepwater oil and gas resources, drilling fluids must withstand extreme temperature differences ranging from seabed low temperatures (0–4 °C) to downhole high temperatures (>200 °C), posing severe challenges to their rheological properties. To overcome issues such as low-temperature thickening and high-temperature viscosity reduction in conventional water-based drilling fluids across wide temperature ranges, developing intelligent rheological modifiers with “flat-rheological” characteristics has become a key technological direction. This paper systematically reviews recent advances in relevant research both domestically and internationally, focusing on four types of rheological modifiers: linear polymers, nonlinear polymers, biopolymers, and nanocomposites. It comprehensively summarizes the constant rheological mechanisms and performance boundaries of these modifiers, identifies the main bottlenecks in current technology, and outlines the future development pathways.

  • 1
• Synthesis and performance evaluation of novel temperature-resistant fiber grafted swellable resin

  MA Chunxu, TIAN Ye, YANG Zhicheng, ZHI Caifu, DONG Xiliang, WANG Chengwen

  Abstract: (68) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To address the issues of easy hydrolysis, excessively rapid expansion rate, and inadequate load-bearing capacity in existing polyacrylic-based expandable resins under high-temperature conditions, this study proposes a novel method for preparing a high-temperature-resistant fiber-grafted expandable resin. By incorporating a high-temperature-resistant five-membered heterocyclic structure into the polymer backbone and reinforcing it with grafted modified polyethylene short fibers, the overall performance of the resin was significantly enhanced. Through systematic optimization of key parameters, including the grafting rate, expansion ratio, water retention capacity, and monomer conversion rate, the optimal reaction conditions for fiber modification and resin polymerization were determined. Thermogravimetric analysis, high-temperature aging experiments, and salt resistance tests demonstrated that the modified resin maintains stable expansion performance under high-temperature conditions of 180°C and in saline solutions with certain mineralization levels. In various complex environments, the maximum expansion time of the resin remained stable at 60 minutes, and the compressive modulus of the gel increased by up to 363% at the maximum expansion ratio. The fiber-grafted expandable resin exhibited excellent delayed expansion properties, high-temperature stability, and superior load-bearing strength, indicating broad application potential in oilfield development areas such as high-temperature fracture and vug plugging and deep high-permeability layer profile control.

  • 1
• Novel Biopolysaccharide GP Gum: Solution Properties and Profile Modification and Displacement Performance.

  LI Zhuangzhuang, SHI Yuqing, GONG Jiayu, ZHU Jie, QIAN Zhihong, WANG Biao, LI Hanzhou

  Abstract: (107) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  In the middle and late stage of oilfield development, the dominant seepage channels lead to the increase of water cut and the decrease of oil production. The existing polymer profile control and flooding system is difficult to meet the requirements of high temperature, high salinity and low permeability reservoirs. In this paper, a new type of biopolysaccharide GP gum was developed, and its solution performance, gelling characteristics, injectability, fluid diversion ability and oil displacement effect were systematically evaluated. The results showed that GP gum was a sphingosine gum with novel structure. Its main chain contained 1→2, 1→4 and 1→6 glycosidic bonds. The monosaccharide composition was mainly glucose and guluronic acid, without rhamnose. It was significantly different from Willan gum and gellan gum. Its solution has the characteristics of "thermal viscosity increasing", and its temperature resistance and salt resistance are obviously better than xanthan gum. The viscosity retention rate is more than 50% at 100 ℃ and 71214 mg/L salinity. GP gum and organic chromium crosslinking agent can form high-strength gel. The gum forming strength under 2% crosslinking agent is more than 20000 MPa.s. The gum forming time is controllable and the strength is stable, which is much better than that of xanthan gum under the same conditions. The core injection experiment showed that the injection pressure of GP gum was low, and the viscosity retention rate after shear resistance was 83.9%, which was significantly higher than that of xanthan gum (63%) and HPAM (39%). In the dual pipe parallel core profile control and flooding experiment, the profile improvement rate reached 91.6% when the permeability difference was 5.47, and the diversion rate of low-permeability layer increased to 67.34%, with outstanding fluid diversion effect. The oil displacement experiment shows that the enhanced oil recovery of GP gum is 25.4%, the comprehensive oil recovery is 67.9%, and the oil displacement effect is significantly better than that of HPAM (9.6%) and xanthan gum (16.5%). GP gum provides a practical technical scheme for high-efficiency profile control and flooding in low-permeability, high-temperature and high salinity reservoirs, and the related achievements can provide an important reference for the popularization and application of biopolysaccharide in oilfield development.

  • 1
• Dynamic Adsorption Influencing Factors and Field Application of Nano Adsorption Oil Recovery Agent

  PAN Binlin, HE Dongyue, XU Hui, LI Bin

  Abstract: (102) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  The development of low- and ultra-low-permeability reservoirs presents significant challenges, as conventional chemical flooding agents often fail to concurrently achieve effective wettability alteration and ultra-low oil-water interfacial tension (IFT). Furthermore, static imbibition tests cannot adequately simulate the actual dynamic reservoir development process. In this study, a novel imbibition agent, SL-1, was formulated by compounding nano-SiO? with an anionic-nonionic surfactant. Experiments were conducted using artificial ultra-low-permeability cores (1～5 mD). Fundamental properties were evaluated via contact angle goniometry, spinning-drop IFT measurements, and static imbibition tests. Nuclear magnetic resonance (NMR) T? spectroscopy was employed to quantitatively characterize dynamic imbibition behaviors. The effects of injection rate, matrix permeability, shut-in duration, and fracture geometry (length and density) on imbibition efficiency were systematically analyzed, followed by two field pilot tests. Results demonstrate that 0.3 wt% SL-1 reduces the IFT to the 10?³～10?? mN/m range and alters the wettability of oil-wet quartz surfaces from a contact angle of 107° to 34°, achieving a static imbibition recovery factor of 31%. Dynamic imbibition is governed by multiple factors, with their influence weights ranked as follows: shut-in duration > permeability > fracture length > fracture density > injection rate, identifying shut-in duration and permeability as the dominant controlling factors. Fracture development expands the fluid-rock contact area, enhancing the imbibition recovery factor of cores with through-going fractures by 51.6% compared to intact cores. Field trials validated the efficacy: in Well S1, the daily oil production increased from 0.8 t to a peak of 6.4 t, with a cumulative incremental oil production of nearly 1000 t; in Well S2, production rose from 0.2 t/d to a peak of 2.2 t/d, representing an eightfold increase over pre-treatment levels. The study confirms that the SL-1 nano-imbibition system effectively optimizes reservoir wettability and reduces interfacial tension, significantly improving the imbibition recovery in low-permeability reservoirs and demonstrating considerable potential for field application.

  • 1
• Study on the adaptability of chemical flooding in high temperature, high salinity and low permeability carbonate reservoir

  Maruicheng, dingmingchen, hudandan, gaoyuan, wuyuanbing, wangyefei

  Abstract: (165) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Chemical flooding in high-temperature, high-salinity and low-permeability carbonate reservoirs is faced with problems such as reduced chemical activity, poor stability and difficult chemical injection, which brings uncertainty to oil displacement effectiveness. The study conducted experiments on interfacial tension, contact angle, viscosity, core injection performance, and core oil displacement by chemicals. It identified the surfactant and polymer suitable for harsh environments, clarified the injection limits of polymers, and compared the oil displacement performance of different chemical systems. Ultimately, the optimal chemical flooding system and method for high-temperature, high-salinity and low-permeability carbonate reservoirs is revealed. The results demonstrate that amphoteric surfactants exhibit superior thermal and salt resistance. Under 78°C and 94,148.0 mg/L, 225068.0mg/L salt water condition, EAB solution with a concentration of 3,000 mg/L could effectively reduce the interfacial tension to 0.006 mN/m and 0.001 mN/m, respectively. Comparative studies of various amphoteric surfactants revealed that interfacial tension decreases with increasing carbon chain length. It indicates a fact that enhancing hydrophobic affinity proves to be an effective strategy for developing ultra-low interfacial tension amphoteric surfactants. Conventional HPAM shows poor long-term stability at 78℃, 94148.0 mg/L, and 225068.0mg/L salt water environment, with viscosity retention rate below 5% after 50 days of aging. In contrast, SAV10 and SAV55 polymers demonstrate better stability, maintaining viscosity retention rates above 80% and 60% respectively after 90 days of aging. In a 3.4×10-3 μm2 core, the SAV10 injection pressure gradient showed continuous elevation without stabilization, making the polymer injection difficult. In a 9.6×10-3μm2 core, SAV10 with concentration ≤200mg/L(0.81mPa·s) the injection pressure gradient stabilized finally, showing certain injection capability. In a 21.0×10-3 μm2 core, polymer with concentration ≤1000mg/L(≤2.8mPa·s) achieved good stability in injection pressure gradient and successful injection. The oil displacements in cores with permeabilities about 10.0×10-3 μm2 demonstrates that single surfactant injection shows limited recovery enhancement: 4.4% increase with 0.3PV injection and 8.1% with 1.0PV injection. Polymer flooding achieves improved oil recovery enhancement of 16.4%. The surfactant foam system demonstrates synergistic effects of ultra-low interfacial tension and sweep-volume enlargement by pressure increase, delivering a peak recovery increment of 27.4%. The SP composite system follows with 24.0% recovery enhancement.

  • 1
• Preparation and Performance Evaluation of Non-precipitating 0rganic Phosphorus Chelating Agent Formula for Plug Removal

  SUN Lin

  Abstract: (106) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  In response to the problem that when conventional chelating plugging removal agents are used in acidizing plugging removal operations in oilfields, the chelates produced after dispersing scale substances are insoluble and prone to block the reservoir, polyamino polyether methylene phosphonic acid (PAPEMP) and 2 - phosphonobutane - 1,2,4 - tricarboxylic acid (PBTCA) were used as the key main agents, and hydrofluoric acid (HF) and dimethyldiallylammonium chloride (DMDAAC) were compounded to prepare a non - precipitating organic phosphine chelating plugging removal agent PPF (including pre - acid PPF - A and main acid PPF - B). Through pH tests, marble corrosion experiments, corrosion experiments of on - site scale samples and cuttings, experiments on measuring the corrosion rate at different times, and experiments on inhibiting the secondary precipitation of calcium fluoride, the physical and chemical properties, scale dissolution ability, slow - rate deep penetration performance, and precipitation inhibition performance of the PPF system were systematically evaluated. The results show that: the pH values of PPF - A and PPF - B are 1.40 and 3.40 respectively, which are significantly higher than those of conventional inorganic acids at the same concentration; PPF - A has a large corrosion amount on marble (calcium carbonate) (the mass difference of corrosion in 24 h reaches 5.78 g), and the mass difference after filtering through quantitative filter paper is positive. The solution is clear to the naked eye, and no calcium chelate precipitation is produced; the corrosion rate of PPF - A on on - site scale samples reaches 57.36%, which is 81% of the corrosion ability of hydrochloric acid with a mass concentration of 10%; the corrosion rate of PPF - B reacting with on - site sandstone cuttings for 24 h is 24.23%, and the corrosion rate continuously increases with the reaction time (2 - 24 h), showing good slow - rate deep penetration performance; the compound system with PAPEMP and PBTCA as the main agents can effectively inhibit the secondary precipitation of calcium fluoride within 72 h, the solution remains clear, and the theoretical inhibition rate reaches 95.87%. This plugging removal agent has the advantages of high pH value, moderate corrosion ability, slow - rate deep penetration, and long - term inhibition of secondary precipitation. It is suitable for oilfield acidizing plugging removal operations to prevent the destruction of the reservoir skeleton and pipeline corrosion, achieve deep slow - rate plugging removal, and improve the difficulty of produced fluid treatment, and can avoid the pollution of the reservoir caused by the precipitation of calcium fluoride or chelates.

  • 1
• Research on the Gelling Mechanism and Long-Term Stability of Temperature-Resistant and Salt-Tolerant Polymer Gels

  HUANG Junli, SUN Jian, LI Xianjie, WANG Jintang, LV Kaihe, YANG Yanlong, SUN Jinsheng

  Abstract: (102) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To address the technical challenges of poor gelation stability and short service life of conventional polymer gels in the high-temperature and high-salinity (HTHS) environments of deep reservoirs, a reinforced polymer gel system was fabricated by compounding the alkaline complexing agent LH-2 and stabilizer WD-1, leveraging the inherent property that polymer gels exhibit superior stability in alkaline media while gelation is inhibited under acidic conditions (pH<5). The gelation regularity and application performance of the developed system were systematically investigated through gelation property evaluation, long-term stability testing, Thermal Gravimetric Analyzer (TGA), and core plugging experiments. Experimental results demonstrate that under the conditions of 45550 mg/L salinity (2000 mg/L divalent ion concentration) and 140 ℃, when the mass fractions of both polymer and cross-linking agent are increased to 0.6%, the gel exhibits a dehydration rate of merely 2.8% after 180 days of aging, with the gel strength maintained at grade D~E. Within the temperature range of 90~140 ℃, the system achieves rapid gelation with a gelation time of 17~24 h. For cores with a permeability of 500×10?³μm², the plugging rate reaches as high as 99.9% and the maximum injection pressure is only 0.19MPa, indicating excellent inject ability and plugging efficiency. This high-temperature resistant and long-term stable gel system provides critical data support and a novel technical approach for the profile control technology in deep HTHS reservoirs.

  • 1
• Research Progress on Chemical Systems for Reducing Minimum Miscibility Pressure in CO? Flooding

  WANG Yahui, SUN Xu, WANG Yi, JIANG Ao, ZHAN Yaohua

  Abstract: (115) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  CO2 flooding technology serves as an important means of enhanced oil recovery (EOR), capable of significantly improving oilfield development efficiency while achieving geological storage of greenhouse gases. However, the high minimum miscibility pressure (MMP) limits the widespread application of this technology in reservoirs. This paper systematically reviews the latest research progress of chemical miscibility enhancers. Based on their action mechanisms and molecular structures, miscibility enhancers are classified into five categories: hydrocarbons, alcohols, surfactants (including hydrocarbon-based, fluorocarbon-based, siloxane-based, and composite systems), microemulsions, and bio-based types. The action mechanisms, molecular design strategies, and key influencing factors of various miscibility enhancers are analyzed in detail. The effects of different injection methods on miscibility enhancement are summarized, and recommendations for future research directions are proposed. This paper provides systematic theoretical guidance and technical references for the optimization of CO2 flooding technology and the development of efficient miscibility enhancers.

  • 1
• Construction and Oil Displacement Properties of Citric Acid - Tris (hydroxymethyl) aminomethane Derived Carbon Dots Nanofluid System

  WANG Lili, SHANGGUAN Yangnan, JIA Junhong, XIONG Weiliang, WANG Yifan, WANG Licheng, GUO Yong, TIAN Qianqian, LIU Lei, WANG Huilin

  Abstract: (151) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To enhance oil recovery in ultra-low permeability reservoirs, carbon dots were synthesized via a facile hydrothermal method using citric acid as carbon source and tris(hydroxymethyl)aminomethane (Tris) as nitrogen dopant. A highly active nano oil-displacement system was then constructed by compounding carbon dots with cetyldimethyl betaine. The structural characteristics of carbon dos were characterized by transmission electron microscopy, Fourier-transform infrared spectroscopy, and zeta potential analysis. Reservoir brine stability, interfacial activity, core wettability, oil film stripping capacity, static oil washing efficiency, and core flooding performance were systematically investigated. Experimental results reveal that the carbon dots possess an average particle size of 5.9 nm and abundant carboxyl, amide, and ester functional groups, with a zeta potential of -6.62 mV. Adjusting the pH of the carbon dot product to weak acidity enables excellent stability of the nano displacement system under reservoir aqueous conditions. The composite system of carbon dots and betaine reduces the oil-water interfacial tension to 0.078 mN/m, boosting interfacial activity obviously. The contact angle of formation water on core slices decreases from 102.4° to 22.2°, achieving wettability reversal. Furthermore, the composite system exhibits outstanding oil film stripping and static oil washing performance, with an oil film removal area of 85.86% and a static oil recovery efficiency of 62.68%. Core flooding tests demonstrate that the carbon dot-betaine composite system raises the incremental oil displacement efficiency by 14.47%, better than single carbon dots and single surfactant. This study provides a reference for the research and development of high-performance carbon dot nano oil displacement system.

  • 1
• Analysis of the compositional differences between wellbore blockages and crude oil, as well as the mechanism of blockage

  LI Jinghui, GUO Bo, HE Xiaoqing, LI Wenxuan, LI Mingxuan, 张龙力

  Abstract: (123) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Aiming at the wellbore plugging problem of two production wells in an oilfield in Xinjiang, the composition and formation mechanism of the plugging materials were systematically investigated by means of component analysis, stability evaluation, hot-stage microscopy, and property comparison experiments. The results show that the dominant factors for plugging in the two wells are significantly different. For Well #1, the plugging material is dominated by inorganic solid phase, with cuttings (toluene-insoluble matter) accounting for 86.21 wt%, indicating a cuttings-dominated inorganic plugging. For Well #2, the plugging material is dominated by organic heavy components, with oil sample (toluene-soluble matter) accounting for 95.72 wt%, in which the asphaltene content is as high as 58.42 wt%, far exceeding that in the crude oil (1.09 wt%), indicating an asphaltene aggregation-dominated organic plugging. The colloidal stability parameter based on SARA fractions shows that the crude oil from Well #2 has a poor stability with a parameter of 2.89, indicating a significant risk of asphaltene precipitation. Hot-stage microscopy observations indicate that, under atmospheric pressure and within the temperature range of 30?°C to 120?°C, temperature has a reversible effect on the asphaltene aggregation behavior of Well #2 crude oil: heating promotes asphaltene dispersion, with the number and size of particles decreasing; cooling accelerates asphaltene precipitation and aggregation, with the number of particles increasing significantly, and small particles with a particle size less than 5?μm are the most sensitive to temperature changes. Compared with asphaltenes in the crude oil, asphaltenes in the plugging material show obvious enrichment characteristics: the aromatic carbon fraction (fA) increases from 0.46 to 0.65, the average molecular weight increases from 2849 g·mol-1 to 3862 g·mol-1, and the number of structural units increase significantly, which is the key internal cause for organic plugging. Furthermore, cuttings can significantly accelerate the particle size growth of aggregates by adsorbing asphaltenes. The settling velocity of asphaltene combined with cuttings is about 219 times that of pure asphaltene particles, aggravating the plugging risk. This study clarifies the core causes and key influencing factors of wellbore plugging in the two wells, providing a theoretical basis for the optimization of anti-blocking and deblocking processes for similar types of oil wells.

  • 1
• Mechanism and Performance of Synergistic CO2/Responsive Surfactant Flooding for Heavy Oil Recovery Based on Interfacial Tension Regulation and In-Situ Emulsification

  JING Bo, ZHU Yuejun, HUANG Bo, ZHAO Chunhua, LI Xinyao, HE Xinyan, GONG Houjian

  Abstract: (791) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To address the bottlenecks of difficult oil-water separation and high environmental burden associated with traditional surfactant flooding for heavy oil recovery, this study designed and constructed a novel CO2-responsive surfactant system. The surface activity, oil-water interfacial behavior, emulsification performance, and oil displacement efficiency of the system were systematically investigated before and after CO2 saturation. The results demonstrate that the surfactant system exhibits a sensitive CO2-responsive characteristic. CO? saturation induces solution acidification, triggering a significant shift in the critical micelle concentration (CMC), which confirms the effective regulation of surfactant molecular self-assembly by CO2. Under simulated reservoir conditions, a significant synergistic effect between CO2 and the surfactant was observed, rapidly reducing the oil-water interfacial tension to an ultra-low level (<10?2 mN/m). Furthermore, the system displays a unique intelligent response behavior characterized by rapid emulsification followed by spontaneous demulsification. Upon CO2 saturation, the initial emulsification rate increased from 85% to 95%, effectively reducing heavy oil viscosity. After 72 hours of static settling, the emulsion underwent complete spontaneous demulsification, achieving an oil-water separation rate of nearly 100%, which significantly simplifies surface produced fluid treatment processes. Core flooding experiments revealed that the CO2-saturated surfactant system improved heavy oil recovery by 12.6% over water flooding, outperforming conventional surfactant systems. This study not only elucidates the microscopic mechanism of CO2-mediated regulation of surfactant interfacial behavior but also provides a crucial theoretical basis and technical support for a new heavy oil development model featuring high-efficiency in-situ emulsification flooding underground and green natural separation on the surface.

  • 1
• Study and Application of Hyperbranched Polymer Oil Displacement Agent Suitable for Low-Permeability Reservoirs

  WU Liwei

  Abstract: (223) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Low-permeability reservoirs are characterized by low permeability, fine pore throats, and high salinity of formation water. Conventional polyacrylamide (HPAM) oil-displacement agents suffer from severe adsorption and retention, insufficient salt tolerance, temperature resistance, and shear resistance, as well as limited oil displacement efficiency. A hydrophobically modified hyperbranched polyamidoamine-acrylamide copolymer (HB-PAO) was designed and synthesized. The polymer features a three-segment molecular structure of “hyperbranched core-linear arm-hydrophobic terminal” and was prepared via a controlled polymerization process of “in-situ initiation and stepwise grafting”. Characterizations including GPC, FT-IR,¹H-NMR, and SEM confirmed the successful construction of its hyperbranched three-dimensional network topology. Performance tests show that HB-PAO exhibits a dissolution time comparable to that of HPAM, while its comprehensive properties are significantly superior: at a shear rate of 2000 s?1, the viscosity retention rate reaches 69%, which is 1.7 times that of HPAM; it maintains excellent viscosity stability under a high salinity of 10×104 mg/L; after aging at 95 °C for 90 days, the viscosity retention rate is 73.6%, 1.9 times that of HPAM. HB-PAO also shows good interfacial activity: at a concentration of 2000 mg/L, the oil-water interfacial tension is reduced by 51.87% compared with HPAM. Core flooding experiments demonstrate that injecting 0.5 PV of HB-PAO solution into low-permeability cores (10-20mD) increases the final oil recovery by 17.8% compared with water flooding and by 9% compared with HPAM flooding. Field tests further verified that this polymer can effectively adjust the fluid injection profile, increasing the average daily oil production of beneficiary wells by 47.8% and reducing the comprehensive water cut by 19.2%. This polymer has been successfully applied, providing a new high-performance oil displacement material for the efficient development of low-permeability reservoirs.

  • 1
• Effect of Crude Oil Components on Emulsion Stability and Demulsification Mechanism

  WANG Chiyu, LI Yuanhao, ZHAO Jianbin, MOU Xiaobo, XIA Yuxiang, ZENG Zekai, ZHENG Cunchuan

  Abstract: (66) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To solve the problem of low-temperature demulsification and dehydration of crude oil at a target joint station, the influence of crude oil components on emulsion stability was first investigated.Crude oil components were separated to prepare model oils, and the interfacial properties, zeta potential, particle size distribution and microstructure of the corresponding emulsions were systematically characterized.The results show that the effects of different components on the stability of water-in-oil (W/O) emulsions follow the order: paraffin wax > resins > aromatics > saturates.Subsequently, the changes in interfacial properties, particle size distribution and microstructure of the crude oil emulsion under the action of demulsifier PR-1 were investigated.Mechanism analysis reveals that the demulsification and dehydration process of the crude oil emulsion mainly undergoes three stages: flocculation, coalescence and sedimentation of emulsified water droplets.The demulsifier first dissolves in the oil phase, then diffuses to the oil-water interface and adsorbs there via molecular motion. It displaces the native active components in crude oil and rearranges to form a new interfacial film with lower strength.This leads to the rupture of the interfacial film and the release of the encapsulated emulsified water droplets, ultimately achieving low-temperature demulsification and dehydration for the target joint station.

  • 1
• Preparation and Channeling Control Performance of CO2-Responsive Gel Particles in Tight Oil Reservoirs

  CHEN Jingwei, LEI Yiming, CHEN Pengyu, WANG Song, FANG Zezhou, DU Daijun

  Abstract: (141) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Based on emulsion polymerization and free radical polymerization methods, using styrene and azobisisobutyronitrile as the main reagents, active polystyrene microspheres were prepared. These were used to initiate the reaction of acrylamide (AM), the CO2-responsive monomer dimethylaminoethyl methacrylate (DMAEMA), the stability crosslinker N,N’-methylenebisacrylamide, and the acid-sensitive crosslinker N,N-diacryloyloxy-bis(2-aminoethoxy)methane to prepare a CO2-responsive gel particle system (CRP) for sealing CO2 channeling pathways in tight oil reservoirs. The structure of CRP was characterized, and its swelling behavior, and CO2 responsiveness were tested. Combined with a high-temperature, high-pressure online NMR displacement system, its ability to enhance CO2 flooding recovery was determined. The results show that as the temperature increases from 30°C to 90°C, the mass swelling ratio of CRP increases from 35.7 to 68.1 times. At 30°C, the median particle size of CRP after swelling equilibrium is 107.2μm, which increases to 118.2μm after contact with CO2, indicating significant CO2 responsiveness. In a tight matrix-fracture dual-media core, after CO2 breakthrough, injecting 0.3 FPV of 0.3% CRP suspension followed by aging for 24 hours and subsequent CO2 injection can enhance oil recovery by 17.43%. The above experimental results demonstrate the feasibility of preventing CO2 gas channeling in tight matrix-fracture dual-media systems.

  • 1
• Clay-based sol for thermal recovery and cleaner production in thin-layer heavy oil reservoir

  ZHANG Jinghui, BAI Yongqing, FU Hongliang, ZHANG Huaihao

  Abstract: (100) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  In thin-layer heavy oil reservoir, severe steam channeling leads to low sweep range, while limited temperature in aqueous displacing fluid restricts its thermally-induced viscosity reduction performance. To alleviate the above-mentioned problems, in this work, a high-temperature clayey sol Bent/PAANa was synthesized to enhance thermal efficiency and alleviate environmental hazards, with bentonite (Bent) applied as the matrix and sodium polyacrylate (anionic polyelectrolyte, PAANa) as the crosslinker. Wherein, the clay platelet percolated network on outer layer of Bent/PAANa sol provides a thermal-insulation coating and lubricating layer, effectively raising the sol temperature and fluidity in pay zone. Meanwhile, the polyanion-clay composite network within the sol endows it with high viscosity, significantly strengthening the displacement efficiency and profile control performance. From core flooding experiments, compared with steam drive, a higher sweep efficiency, displacement pressure and oil recovery was obtained, up to 27.2%, 169 kPa and 38.2%OOIP, after Bent/PAANa sol injection.

  • 1
• Development and application of profile control and viscosity reduction system for heavy oil reservoirs after water flooding

  YUN Qingqing, LIU Xiaoli, DU Jie, LUAN Huoxin, LIAN Zete

  Abstract: (262) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  In response to the deteriorating oil production effect in the deep layers of the heavy oil reservoir in the Ji7 well area of Xinjiang Oilfield after water flooding, with a significant increase in water cut in recent years, and the combined influence of planar and profile contradictions, severe water flooding and water channeling, high crude oil viscosity, and low reservoir utilization efficiency, this paper conducted a formula evaluation study on the profile control system and viscosity reduction system through the idea of profile control + viscosity reduction， and determined the effectiveness of the "profile control + viscosity reduction" system through numerical simulation and field tests.The results show that the developed profile control system（0.35% polymer + 0.35% phenolic crosslinking agent + 0.2% additive A + 0.15% additive B）exhibits a 90-day viscosity retention rate of 70%, viscosity loss of less than 30% under different shear conditions, and a plugging efficiency of over 95% under different permeability conditions, indicating good stability and plugging performance.; the viscosity reduction rate of 0.5% viscosity reducer reaches 95%, and the indoor oil displacement efficiency of the viscosity reduction composite system (0.5% CA301 + 1500 mg/L polymer) is more than 10%. Through numerical simulation of the fluid flow field distribution before and after the treatment, the well group for the field pilot test was selected. Field application shows that after the profile control and viscosity reduction measures, the comprehensive water cut of the well group decreased by 20%, and the daily oil production increased to 20 t/d, with significant results.

  • 1
• Key additives and system of anti-ultra-high temperature and long-term stable oil-based drilling fluid

  HU Jing, WANG Jun, HE Tao, XIAO Fengfeng, DUAN Ming, LI Xinliang

  Abstract: (187) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Aiming at the problems of few types of anti-ultra-high temperature oil-based drilling fluids (OBDFs) for deep ultra-deep drilling, immature supporting technology and insufficient long-term stability at ultra-high temperatures, an anti-ultra-high temperature and long-term stable OBDFs was developed. The synthesis methods and mechanisms of the key additives were described, and the performance evaluation was carried out. The modified fatty acid primary emulsifier and fatty acid amide auxiliary emulsifier were prepared by using unsaturated fatty acid, maleic anhydride, and fatty alkylamine. They exhibited good emulsion stability. The demulsification voltage was higher than 400V. Amphiphilic rheology modifier was prepared by the reaction of dimer fatty acid with diethanolamine, and aliphatic diamine, which could improve the aggregation state of emulsion droplets, with low viscosity and high gelling effect. The water-based acrylic resin was modified by ester monomers to prepare a high-temperature resistant composite fluid loss agent, which was stable in oil and had outstanding fluid loss performance. Furthermore, a set of OBDFs with temperature resistance of 240°C was constructed with these developed treatment agents as the core materials. The viscosity and gel strength of this drilling fluid were stable. The HTHP fluid loss was less than 5 mL, and the sedimentation stability was good after vertical aging at 240°C for 5 days. The demulsification voltage was higher than 1000 V. This research can provide guidance for the development of safe and efficient drilling and completion fluids for deep wells.

  • 1
• Optimization and Application of a Nano-ZrO? Enhanced Instant-Soluble Polymer Fracturing Fluid System for 230°C High-Temperature Tight Gas Reservoirs

  CHENG Yuxiong, WU Guangai, CAO Yanfeng, PENG Chenyong, SHI Weiqi, CHEN Minggui

  Abstract: (180) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Addressing the challenges in fracturing the WC ultra-low permeability, tight sandstone, high-temperature, and high-pressure gas reservoir (wellhead pressure: 79 MPa; closure pressure: 86 MPa; temperature: 230°C), such as high treating pressure, proppant placement difficulty, fracture extension complexity, inadequate temperature resistance of conventional fluids, and limited freshwater availability, this study developed a seawater-based, nano-enhanced fracturing fluid stable at 230°C. The optimized formulation (0.5% SRP-1 + 0.02% hydrophilic nano-ZrO? + 0.6% YCJ-1+0.2% pH buffer+ 1% KCl + 0.5% ZP-1) maintained a viscosity of 172 mPa.s after shearing at 230°C and 170 s?1 for 2 h, broke completely to 3.23 mPa.s, and caused less than 19% core damage. A composite proppant placement strategy using a blend of small, medium, and large mesh sizes (40/70: 30/50: 20/40 = 1:2:1), which achieved a fracture conductivity of 15 D.cm under 86 MPa closure pressure, ensuring long-term flow capacity while mitigating placement difficulties. Field applications confirmed that this integrated approach successfully addressed the technical challenges, significantly increasing proppant placement efficiency and stimulation performance, providing robust technical support for the efficient development of similar offshore high-temperature gas resources.

  • 1
• Preparation and Performance Evaluation of Temperature-resistant and Salt-resistant Environment-friendly Lubricant for Horizontal Well Drilling of Shale Oil

  Wei Changlian, Wu Jieying, Jiang Hongzong

  Abstract: (280) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  In response to the problems such as the failure of traditional lubricants to function properly in the high-temperature and high-salt environment during the drilling of shale oil horizontal wells, as well as their poor environmental performance and insufficient on-site adaptability, this study used 2-aminothiazole and long-chain fatty acids as the main raw materials. Through amide formation reactions, amide compounds containing a thiazole ring and long-chain alkanes were generated. Then, these compounds were combined with vegetable oil, polyoxyethylene castor oil EL-40, Span 80, and polyether defoamer to form a microemulsion-type lubricant named WRH. The molecular structure was characterized by infrared spectroscopy and nuclear magnetic resonance. Meanwhile, the effects of temperature, salt content, WRH content, etc. on the extreme pressure lubrication coefficient, mud cake adhesion coefficient, anti-wear performance and wetting performance were investigated. Based on this, the mechanism of the action of WRH was analyzed. Finally, the influence on the performance of the drilling fluid and the environmental protection performance were evaluated.The results of molecular structure characterization confirmed that the amino group of 2-aminothiazole successfully underwent an amide reaction with the carboxyl group of long-chain fatty acids, forming a molecular structure that combines polar adsorption groups with hydrophobic lubricating chains.The performance evaluation results showed that at 180℃ high temperature and 15×10?mg/L NaCl high salt conditions, adding 3.0% lubricant WRH could reduce the extreme pressure lubrication coefficient and mud cake adhesion coefficient of the drilling fluid to 0.051 and 0.086, respectively, lowering by 89.2% and 81.9%. The four-ball friction test indicated a friction coefficient of 0.15, a reduction of 53.1%. The wear scar diameter was only 528.6μm, a reduction of 37.6%. The interface wetting test revealed that WRH could increase the contact angle of the steel plate surface from 37.8° to 118.6°, significantly enhancing the hydrophobicity of the shale surface. The mechanism analysis demonstrated that the polar group of the thiazole ring in WRH could form strong adsorption with the metal/ shale surface through hydrogen bonds, while the hydrophobic chain of the long-chain fatty acid was oriented and arranged at the interface to form a dense lubricating film. Meanwhile, the conjugated structure of the thiazole ring could resist the damage of the high-temperature and high-salt environment to the adsorption film, achieving long-term lubrication. The field application test showed that during the drilling of a shale oil horizontal well, adding WRH resulted in a 24% to 27% reduction in drill string torque and a 17.7% increase in drilling efficiency. Moreover, the performance of the drilling fluid system remained stable without environmental pollution issues. This study provided key additives and theoretical support for efficient and green drilling under complex conditions of high temperature and high salt in shale oil horizontal wells, and has significant engineering application value.

  • 1
• A newself-settling high-strength casing leak sealing agent for offshore oil fields

  GUO Yonghua, WANG Xiaolong, XU Guorui, GAO Yahui, ZHOU Jingjing, TIE Leilei

  Abstract: (182) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Objective: As offshore oil and gas exploration and development progressively advance into deepwater areas, wellbore integrity management faces severe technical challenges, and existing chemical plugging systems are unable to fully satisfy the performance requirements. This study aims to develop a novel plugging agent that integrates self-settling characteristics, high strength, and long-term stability, thereby providing a reliable solution for wellbore integrity restoration in offshore oil and gas fields. Methods: Lignin was first modified via hydroxymethylation with formaldehyde under alkaline conditions to introduce reactive hydroxymethyl groups, and then copolymerized with phenol and formaldehyde to yield the lignin-modified phenolic resin plugging agent precursor. The structure and thermal stability of the plugging agent were characterized by Fourier transform infrared spectroscopy (FT-IR) and thermogravimetric analysis (TGA). Injectivity and self-settling performance were evaluated using a rotational rheometer and a density meter. Compressive strength of the cured samples was measured with a universal testing machine. Gas sealing performance was assessed using a full-scale annular simulation device to verify the plugging effectiveness under conditions approximating actual working environments. Results: FT-IR analysis confirmed the successful hydroxymethylation modification of lignin. TGA demonstrated that the plugging agent remained structurally stable below 300℃, with a total mass loss of only 3.6%. Under the optimal formulation (formaldehyde 30 mL, phenol 40 mL, lignin 10 g), the agent exhibited a density of 1.18 g/cm3, enabling self-settling in the annulus, and a viscosity of 103 mPa·s at a shear rate of 170 s?1, displaying favorable pumpability and shear-thinning behavior. The cured samples achieved an initial compressive strength of 12.5 MPa, representing a 30.2% improvement over the unmodified phenolic resin (9.6 MPa). After 150 days of aging at 80℃, the compressive strength was maintained at 12.48 MPa, with a strength retention rate exceeding 99%. In the full-scale annular simulation sealing test, the plugging agent sustained a gas pressure of 6.89 MPa for 2 minutes without leakage in a narrow 5 cm annulus, and the cured body exhibited excellent bonding with the casing wall. Conclusion: This study successfully developed a novel lignin-modified phenolic resin plugging agent. The agent integrates self-settling injectivity, high strength, and long-term durability, and its reliable sealing capability under narrow-annulus and high gas pressure conditions was verified by full-scale experiments. The grafting of lignin via hydroxymethylation, which participates in crosslinking and curing, enhances crosslinking density and interfacial adhesion, constituting the core mechanism underlying the improved performance. This plugging agent can provide effective technical support for wellbore integrity management in offshore oil and gas fields.

  • 1
• Research and application of CO? flooding foam channeling control system in tight sandstone reservoirs

  YAN Jian, ZHANG Bin, JIA Hao, ZHU Ji-yun, DANG Mei-qi, QI Kai, GONG Hang

  Abstract: (163) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Aiming at the characteristics of tight sandstone reservoirs such as deep burial, high temperature and strong heterogeneity, as well as the key problems in CO2 flooding including low sweep efficiency, performance attenuation of conventional foam for profile control and flooding under high temperature, and frequent gas channeling, this study synthesized the zwitterionic foaming agent CR-Z16 through molecular structure design, and constructed a high-stability CO2 foam channeling control system by combining it with modified nano-SiO2. Systematic laboratory evaluation tests were carried out on the system, covering foaming performance, temperature, salt and pressure resistance, rheological properties, interfacial tension, as well as core plugging and oil displacement. Meanwhile, field application verification was conducted. The results show that the optimal formulation of the system is formation water + 0.4% CR-Z16 + 0.1% modified nano-SiO2 which maintains excellent foaming and foam stability even under the conditions of 110℃ and 100,000 mg/L salinity. The interfacial tension between the system and crude oil decreases to 0.19 mN.m-1 at 23 MPa, exhibiting ultra-low interfacial tension characteristics. Moreover, the system has a significant shear thinning effect, which can meet the requirements of formation seepage. Core tests indicate that compared with water flooding, this system can increase the crude oil recovery degree by 28.6%, and by 28.7% compared with CO2 flooding. Field application results show that the system can significantly increase the gas injection pressure, the average daily oil production of the well group increases from 2.0 t to 4.6 t, and the gas-oil ratio decreases from 197.6 m3/t to 44.3 m3/t. It effectively blocks the gas channeling channels and greatly improves the development effect. This research provides technical support and theoretical basis for gas channeling control in CO2 flooding development of tight sandstone reservoirs.

  • 1
• Preparation, Properties and Field Applications of Heat- and Salt-Resistant Friction Reducers

  Fang Yanqiu

  Abstract: (138) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  (Objective) To address the challenge of reusing fracking flowback water, where the high salinity causes a sudden drop in the viscosity of friction reducers and a decline in their performance, and to achieve the efficient recycling of fracking flowback water. (Methods) A temperature- and salt-resistant drag-reducing agent was synthesised using a dispersion polymerisation method, with acrylamide (AM) forming the main chain of the copolymer and 2-acrylamide-2-methylpropanesulfonic acid (AMPS) optimising hydrophilicity and salt resistance. A third hydrophobic monomer was introduced, and the optimal synthesis scheme was determined through comparative screening of the copolymer systems’ properties; Regarding performance testing, a six-speed viscometer was used to determine the apparent viscosity of the copolymer, whilst a rheometer was employed to assess its high-temperature rheological properties and evaluate its thermal stability. Scanning electron microscopy (SEM) was utilised to examine the microstructure of the copolymer and analyse its spatial structural characteristics in high-salt environments. Concurrently, field applications were conducted to verify its practical performance. (Results and Conclusions) Screening experiments identified octadecyl dimethyl allyl ammonium chloride (DMAAC-18) as the key functional monomer; by leveraging the synergistic effects of hydrophobic association and electrostatic interactions, it significantly improves the salt tolerance and rheological properties of the drag-reducing agent. The optimal synthesis conditions were a monomer mass ratio of AM:AMPS:DMAAC-18 = 9:1:0.15, a monomer concentration of 25 wt%, and a polymerisation temperature of 35 °C. Under these conditions, the P18 terpolymer prepared exhibited an apparent viscosity of up to 183.6 mPa·s, with the high-temperature rheological final viscosity stabilising at 36 mPa·s. Microscopic characterisation results confirm that this terpolymer can stably form a continuous porous network structure in high-salt media, effectively enhancing the fracking fluid’s salt resistance and sand-carrying capacity. Field application at Well H1 demonstrated that the slickwater fracturing fluid formulated with this temperature- and salt-resistant friction reducer exhibited stable and reliable performance during operation. The fracturing operation resulted in significant increases in oil and gas production, providing a viable technical solution and theoretical support for the resource recovery and reuse of shale oil fracturing flowback fluids.

  • 1
• Preparation and properties of reservoir temporary plugging protection system for horizontal well water plugging

  Chang Zheng, Gao Yahui, Tie Leilei, Wang Haoyi, Liu Fenggang, Li Jianye

  Abstract: (168) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  The proportion of ultra-high water-cut horizontal wells in offshore oilfields is relatively high.? And due to the problem of oil-water co-plugging, the success rate of water plugging is very low. In order to improve the success rate of water plugging in horizontal wells, a reservoir temporary plugging protection system was prepared using Span80, AES and CAB as emulsifiers, and the 17 million molecular weight salt-resistant polymer was used as stabilizer.The types and concentrations of emulsifiers and stabilizers in the temporary plugging protection system were determined through molecular dynamics simulation and laboratory experiments. The optimal preparation condition for the temporary plugging protection system were: 3% emulsifier ( Span80:AES:CAB = 8:1:1 ) + 0.2% polymer ( 17 million salt-resistant polymer ). The performance of the temporary plugging protection system was tested by liquid separation time method and one-dimensional sand filling tube model. The results showed that this system had good emulsification stability that no drninage phenomenon within 4 days, oil-water selectivity and permeability recovery ability under high temperature and high salt conditions. And the temporary plugging protection system effectively realized the liquid flow diversion under the permeability difference was less than 4 and the injection rate was 2.0mL/min. In general, the temporary plugging protection effect of the oil layer is remarkable. This study provides theoretical basis and technical support for reservoir protection in offshore oil horizontal well water plugging operation.

  • 1
• Development and Properties of Degradable Temporary Plugging Agent for Medium-Low Temperature Reservoirs

  QV Bo, ZHAO Xiangyang, ZHANG Ming, ZHANG Xiaoping, JIA Jun, LI Tingting, ZHAO Kun

  Abstract: (193) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To address the challenges of drilling fluid loss, reservoir contamination, difficulties in post-operation plug removal, and poor degradation controllability of temporary plugging agents in fractured reservoirs, a degradable temporary plugging agent ZDJ with a core–shell structure was developed. This agent was synthesized using natural waxy starch and polylactic acid ( PLA ) as the core materials via graft copolymerization to form starch-grafted PLA copolymer ( St-g-PLA ) , which was further encapsulated by a cross-linked polyacrylamide shell. This study systematically investigated the chemical structure, thermal stability, particle size distribution, degradation behavior, plugging capacity, and reservoir protection performance of ZDJ. The results demonstrated that ZDJ particles exhibited excellent thermal stability. The core–shell structure effectively delayed the degradation process, allowing the degradation period to be controlled within 5–20 d. Sand bed and wide-fracture plugging tests showed that ZDJ achieved pressure-bearing capacities of up to 8 MPa and 5 MPa in 3 mm and 5 mm fractures, respectively, indicating superior plugging performance. Core flow experiments revealed that the permeability recovery value after degradation exceeded 94%, with minimal reservoir damage. The ZDJ temporary plugging agent fulfilled the design objectives of "controllable plugging, complete degradation, and reservoir protection, .

  • 1
• Optimization of Foam Mobility Control for High-Temperature and High-Salinity Reservoirs

  ZHENG Xiaojie, LIU Xueli, ZENG Liyou, LI Zhenghui, ZHAO Jianguang, DUAN Hongze, XU Qiaoqiao, SUN Lin

  Abstract: (111) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  The Lower Triassic formation in Block 9 of the Tahe Oilfield is characterized by high temperature (108?°C), ultra-high salinity (21.8×10??mg/L), and is currently undergoing development at a high water cut stage. Although N? foam flooding has demonstrated significant potential for enhancing oil recovery in this reservoir, its effectiveness in establishing long-term flow resistance in water-channeling pathways remains short-lived. To address this limitation, a novel foam system (TLBO) was developed, and its gas-liquid injection ratio in an oil-bearing environment were systematically optimized. The TLBO system—comprising an anionic–nonionic hydrocarbon surfactant, fluorocarbon surfactant, and modified biopolymer—leverages synergistic effects in viscoelasticity enhancement and interfacial stabilization. Under oil saturations of up to 40%, TLBO exhibited less than a 4% decrease in foam volume and a 35% reduction in drainage half-life, while maintaining a foam half-life exceeding five hours. After aging for three months under reservoir temperature and salinity conditions, the system still generated stable foam at 20% oil saturation. Experimental results revealed that crude oil had a more pronounced detrimental effect on foam performance in porous media than in bulk phase. Consequently, the previously optimal gas–liquid ratio of 5:1 (established under oil-free conditions) failed to provide effective mobility control in the presence of oil. By reducing the gas–liquid ratio, the effective viscosity of the TLBO foam increased significantly. Notably, below a residual oil saturation of 13%, adjusting the gas–liquid ratio to 1:2 restored the foam"s mobility control performance to a level comparable with that observed in oil-free conditions. These findings provide critical insights into the design and field application of foam systems for high-temperature, high-salinity reservoirs, and support improved recovery efficiency in challenging reservoirs such as those in the Tahe Oilfield.

  • 1
• Demulsification performance of cashew phenol-based polyether ester demulsifiers

  ZHOU Yue, Wang Ling, SUN Yubo, ZHU Xianjiang, WANG Jun

  Abstract: (190) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  To develop a green synthesis route for cashew phenol-based polyether ester demulsifiers, replacing the traditional ethylene oxide and propylene oxide routes. Biomass cashew phenol and formaldehyde were used as raw materials to prepare cashew phenol aldehyde resin initiators via condensation reaction. Then, ring-opening polymerization with ethylene carbonate was conducted under the catalysis of potassium carbonate. The chemical structure of the target product was confirmed by infrared spectroscopy and 1H NMR. The demulsification performance evaluation showed that under the conditions of a demulsifier dosage of 200 mg/L, 70 ℃, and 2 h, the dehydration rate reached up to 92.25%. This study provides a new idea for the development of environmentally friendly and efficient crude oil demulsifiers, and expands the application of cashew phenol in the field of high value-added fine chemicals.

  • 1
• Effect of modified nano-SiO₂ on the stability of foam flooding system

  汤瑞佳, chen longlong, tian weiwei, zhao cong, gao zhuolin

  Abstract: (284) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  The stability of a foam flooding system is one of the main factors affecting the enhanced oil recovery (EOR) efficiency of foam flooding technology. Using silica nanoparticles (SiO?) as foam stabilizers can reduce the impact of high salinity, high calcium ion concentration, and other factors on foam performance, thereby improving foam stability. However, conventional silica nanoparticles suffer from poor dispersibility, a tendency to aggregate, lack of functionality, and high cost, which severely limits the application of foam flooding technology. In this paper, the effects of different hydrophilic/hydrophobically modified nano-SiO?on the stability of foam flooding systems are systematically investigated.Six types of nanoparticles (MA, MB, NA, NB, HA, HB) with different hydrophilic and hydrophobic properties were prepared by homogenizing and heterogeneous modifying nano-SiO2 with different silane coupling agents. Their structures, dispersibility and wettability were characterized by FTIR, particle size analysis, Zeta potential, light transmittance and wetting Angle. The amphiphilic modified nano-SiO2 has the best dispersion stability, followed by the hydrophilic modified one, and the hydrophobic modified one is the worst. Both hydrophilic and amphiphilic modified nano-SiO2 can enhance the water wettability of the core surface, and the minimum core contact Angle can be reduced to 39.6°. In the evaluation of foam performance, the carboxylic acid hydrophilic modified NA has the best foam stabilization effect, with a foam half-life of 108 min and a foam comprehensive index of 16,087.50 mL·min. NA enhances the liquid film strength, slows down the drainage and roughening rate, and significantly improves the foam stability through the hydrophilic and hydrophobic properties of surface functional groups and their arrangement behavior and synergistic effect at the gas-liquid interface. The nanoparticle NA stabilized foam system has good deformability, blocking property and emulsifying oil-carrying capacity in the pore structure.

  • 1
• Experimental Study on Mechanism of Micro-Nano CO? System for Enhancing Shale Oil Recovery

  YI Haiyou, SUN Cuiling, ZHAO Xiaochun, ZHANG Xinyin, CHEN Zhenwan, GUO Yuangang, YU Yu, HUI Lei

  Abstract: (153) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Micro-nano bubble flooding is an emerging enhanced oil recovery (EOR) technique. However, its phase behavior, stability, and oil displacement mechanisms remain unclear under high-temperature, high-pressure (HTHP) conditions, especially in the supercritical state. In this study, an improved fluid particle analysis system was adopted to achieve in-situ characterization of the size and concentration of micro-nano bubbles at HTHP conditions. On the basis of clarifying the evolution laws of the size and concentration of micro-nano CO? dispersed phases under varying temperatures and pressures, the morphological stability of micro-nano CO? dispersed phases was evaluated under variable temperature-pressure conditions. Core flooding experiments of micro-nano CO? in shale were conducted, combined with the analysis of concentration variation, dynamic instability index, and CO? gas release volume during the displacement process, to reveal the phase transition characteristics and oil displacement mechanisms of the micro-nano CO? system. Results show that the average diameter of the laboratory-prepared micro-nano CO? system ranges from 223 nm to 386 nm, exhibiting a typical micro-nano scale distribution. When the pressure exceeds the critical pressure of CO?, the dispersed phase transforms into a supercritical fluid state, while the system still maintains a two-phase structure with the aqueous phase as the continuous phase and supercritical CO? as the micro-nano dispersed phase. The volume expansion rate of the micro-nano CO? dispersed phase gradually slows down with the increase of temperature and pressure, whereas the concentration decay rate shows no obvious correlation with temperature and pressure. During shale oil displacement, the micro-nano CO? dispersed phase gradually converts into CO? gas at a constant concentration decay rate, endowing it with stronger pore penetration capacity and forming a dual synergistic oil displacement mechanism of "micro-nano dispersed phase flooding + gas flooding". The cumulative oil recovery reaches 43.4%, which is 15.6 percentage points higher than that of the bubble-free base fluid. Reducing the average diameter and increasing the concentration of the CO? dispersed phase contributes to an improvement in oil displacement efficiency by 2.4 to 6.4 percentage points. This study verifies that the micro-nano CO? system still possesses favorable stability and oil displacement performance under supercritical conditions, which can provide theoretical and technical support for the efficient development of shale oil.

  • 1
• Quality Surveillance of Drilling Fluid Materials: Current Status, Challenges and Strategies

  LIU Changyue, CHEN Ziyu

  Abstract: (178) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  The exploration and development of global oil and gas resources are expanding into complex areas such as deep, ultra-deep, and unconventional formations. Drilling engineering has increasingly high quality requirements for drilling fluid materials. However, the currently uneven quality of drilling fluid materials poses significant risks to drilling operations, wellbore quality, and environmental protection. This study aims to identify the predicaments faced by China's oil and gas exploration enterprises in drilling fluid material quality management, pinpoint the critical factors affecting quality performance, and propose effective countermeasures to enhance the efficiency of oil and gas exploration in China. A systematic analysis of the quality control mode and application effects of drilling fluid materials by large oil exploration and development enterprises such as CNPC, combined with statistical results of enterprises and products certificated by CNPC in the past 10 years, reveals prominent issues in the quality supervision of drilling fluid materials in China's oil exploration and development process. These issues include an imperfect standard system and inadequate implementation, complex additive components with insufficient effective components, uneven product quality in the market, limitations in quality inspection and evaluation methods, insufficient attention to environmental protection and waste disposal, etc. It is found that the current surveillance mode targeting the functional performance of drilling fluid materials is the fundamental cause of the current quality issues of drilling fluid materials. It is proposed to improve the standard system and establish a quality control mode centered on chemical composition analysis throughout the entire quality surveillance lifecycle, providing technical support for China's oil and gas enterprises in carrying out quality control of drilling fluid materials.

  • 1
• Preparation and Application of Selective WSO/Sand Stabilization Integrated Particles for High Water-Cut and Sand-Producing Reservoirs

  ZHU Liguo, CHEN Weiyu, ZHANG Yanhui, WEI Ziyang, WANG Jinlin, JI Wen

  Abstract: (238) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  Aiming at the dual technical challenges of WSO and sand control in high water-cut and sand-producing reservoirs, a kind of selective WSO/sand stabilization integrated particle was developed by using oil-soluble resin particles, sodium-based bentonite, lignosulfonate dispersant, and cationic polyacrylamide as main raw materials.Performance tests including sand stabilization and selective WSO show that:The median particle size of this particles is 8.51 μm and the water-phase dissolution rate is 9.83% with a core plugging rate of 84.5%, while the oil-phase dissolution rate is 82.61% with a core plugging rate of 15.8%. It can bond sand grains in the core into clusters, increasing the median sand grain size by more than 8.8 times and the critical sand-producing velocity by more than 20 times.indicating an obvious selective plugging and sand stabilization effect.

  • 1
• Evaluation and Mechanism of Crude Oil Composition on Enhanced Oil Recovery by Low-Salinity Water Flooding

  LI Ye, TAO Jin, REN Jingbao

  Abstract: (221) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  The oil displacement efficiency of low-mineralization brine is mainly influenced by the interaction among crude oil, brine and rock. Clarifying the relationship among the three is crucial to understanding the dominant mechanism of enhanced oil recovery (EOR) by low-mineralization brine. High-temperature and high-pressure core flooding experiments were conducted on various crude oil samples with different emulsion formation capabilities, including spontaneous imbibition of high-mineralization brine and displacement by low-mineralization brine. The injection process of low-mineralization brine in the tertiary oil recovery mode was simulated to investigate the impact of crude oil microemulsion formation capability and rock wettability changes on the recovery rate of low-mineralization brine flooding. The results show that the cumulative recovery rates of high-mineralization brine spontaneous imbibition and water flooding for the eight oil samples range from 37.6% to 55.9%. When low-mineralization brine is continuously injected in the tertiary oil recovery mode, the recovery rate can be further increased by 0.5% to 10.8%. The stronger the microemulsion formation capability of the oil sample, the higher the recovery rate of low-mineralization brine flooding, but the upper limit of the recovery rate increase by low-mineralization brine flooding is 11%. When the crude oil particle dispersion ratio is greater than 7, the recovery rate of low-mineralization brine flooding for this oil sample can reach more than 5%. Low-salinity brine enhances oil recovery through two mechanisms. On one hand, it forms emulsions with crude oil, promoting the stripping of oil from rock surfaces and the rearrangement of active components, enhancing water-rock reactions and shifting wettability to water-wet. On the other hand, emulsification induces the Jamin effect to increase seepage resistance, raising injection pressure and displacement differential pressure under constant-rate injection, and expanding sweep efficiency. The findings provide a reference for the application of low-salinity brine flooding and the precise screening of suitable reservoirs.

  • 1
• Factors Influencing the Oil Displacement Efficiency of Alkali-Free Binary System Assisted by Nano-SiO2 in Low-Permeability Reservoirs

  WU Jingchun, FU Zulong, SHI Fang, Li Ziqiang, Zhang Chunlong

  Abstract: (403) HTML (0) PDF (0.00 ByteKB) (0)

  Abstract:

  An alkali-free composite system, denoted as CHS-x (where x represents the nano-SiO? concentration), was constructed comprising anionic heavy alkyl benzene sulfonate (HABS), zwitterionic cocamidopropyl hydroxysulfobetaine (CAPH), and nano-SiO?, tailored for the low-permeability reservoir characteristics of a specific block in the Changqing Oilfield. The CHS-x systems were characterized via FTIR, particle size analysis, and SEM, followed by evaluations of interfacial tension (IFT), wettability alteration, emulsification performance, and adsorption behavior on reservoir rocks. Experimental results demonstrated that the CHS-0.15% formulation maintained an IFT in the order of 10?3 mN/m after 60 days of static aging at 45°C and a formation water salinity of 11,000 mg/L, exhibited a water separation rate of only 26% after 30 days, and effectively altered oil-wet core slices to weakly water-wet conditions (reducing the contact angle from 105.2° to 61.2°), with nano-SiO? significantly enhancing resistance to adsorption losses. Core flooding simulations indicated that injecting 0.7 PV of the CHS-0.15% system (composed of 0.15 wt% nano-SiO? and 0.3 wt% surfactants with an HABS:CAPH mass ratio of 7:3) increased oil recovery by 28.63% compared to water flooding, showing enhanced recovery across permeability contrasts of 2 and 5; these findings provide targeted technical insights for addressing development challenges in low-temperature, low-permeability reservoirs analogous to those in the Changqing Oilfield.

  • 1

• Research Progress on the Diffusion of CO2 in Crude Oil

  DU lin，LIU wei，CHEN Xingyi，QING Xiaoyuan，REN Xuefei

  2019,36(2):367-372, DOI: 10.19346/j.cnki.1000-4092.2019.02.034

  Abstract: (1745) HTML (0) PDF (1.44 MKB)(7745)

  Abstract:

  Diffusion of CO2 in oil phase plays an important in enhanced oil recovery，since its impact on the recovery improvement percentage and oil viscosity reduction percentage. The research progress on the CO2 diffusion coefficient measurement methods including direct method and indirect method，were summarized. The difference of mathematic models and research progress of indirect method were pointed out in this paper. Based on the summary，it is pointed out that the improving the analysis of impact factors，enriching the research dimension，and improving the study of diffusion law in different scale pores will become the focus and hotspot of the future.

• Research and field Application of High Content of Condensate Oil Resistance foam Unloading Agent

  WU Junwen1，ZHANG Rusheng1，WANG Haibo1，CEN Xueqi1，JIA Wenfeng2，Xiao Zaixin3

  2019,36(3):508-512, DOI: 10.19346/j.cnki.1000-4092.2019.03.023

  Abstract: (1465) HTML (0) PDF (1.71 MKB)(5807)

  Abstract:

  Longfengshan gas field water well is characteristic of deep well depth，high gas temperature（104—149℃）and super high content of condensate oil for some blocks. A kind of organic ammonium salt type cationic fluorocarbon surfactant was synthesized，and it was mixed with the existing foaming agent as a ratio of 1∶15，which was composed of zwitterionic surfactant cocoamidopropylbetaine and sodium alpha-olefin sulfonate at ratio of 10∶1，thus the foam unloading agent PQ-Y was developed. Its foaming ability，foam stabilizing ability and liquid carrying ability were tested and field test was also carried. Laboratory tests showed that the initial foaming height Ho and foam height after 5 min H5 of the foam unloading agent were 194 mm and 186 mm，respectively，after aging at 160℃ for 14 h，and Ho and H5 were 189 mm and 180 mm when the salinity was as high as 250000 mg/L，and Ho and H5 were 171 mm and 168 mm，respectively，when the volume fracion of petroleum ether was 50%，its liquid carrying rate was as high as 8 mL/min，which indicated that the foam unloading agent PQ-Y was resistant to the condensate oil. The field test of the foam unloading agent in Longfengshan north 201-XY well showed that，the average gas production increased from 7256 m3/day to 11329 m3/day，increasing by 56%，the average differential pressure between tubing and casing dropped from 2.66 MPa to 2.38 MPa，felling by 10.5%，both liquid yield and gas production were obvious，which proved that the foam unloading agent PQ-Y could meet the demand of drainage gas recovery for high content condensate oil gas field

• Development and Application of Heavy Oil Viscosity Reduction Technology at Home and Abroad

  ZHOU Linbi，QIN Bing，LI Wei，WANG Zheng

  2020,37(3):557-563, DOI: 10.19346/j.cnki.1000-4092.2020.03.032

  Abstract: (1365) HTML (0) PDF (1.18 MKB)(5256)

  Abstract:

  Viscosity reduction and mobility improvement are very crucial in heavy oil recovery. The mechanism，development and application of main viscosity reduction methods at home and abroad were discussed and compared，including thermal treatment based on steam injection，fire flooding，emusification，catalytic reaction，solvent dilution and microbial viscosity reduction. The characteristics and disadvantages of these methods were summarized. Finally，the development directions of heavy oil viscosity reduction technology were proposed.

• Microscopic Flooding Mechanism Experiment Visualization of 2-D Smart Black Nano-card

  WU Weipeng1，2，HOU Jirui1，2，QU Ming1，2，WEN Yuchen1，2，LIANG Tuo1，2，YANG Jinbin1，2，ZHAO Mengdan1，2

  2020,37(1):133-137, DOI: 10.19346/j.cnki.1000-4092.2020.01.023

  Abstract: (2189) HTML (0) PDF (2.35 MKB)(4990)

  Abstract:

  The 2-D smart black nano-card is a new nanosheet material which is independently developed by the institute of enhanced oil recovery from china university of Petroleum（Beijing）. The nano-card has the advantages of small size（80×60×1.2 nm）and large specific surface area（57 m2/g）. In this paper，2-D smart black nano-card displacement experiments was carried out with different porosity and permeability two-dimensional visualized models. Through analyzing the influence factors such as core permeability， particle concentration and injection rate on oil displacement effect，the migration rules and microscopic seepage mechanism of the 2-D smart black nano-card system were studied. The experiment results revealed that the nano-card had advantage hydrophile-lipophile balance（HLB）. The wettability of the rock surface could be changed，the wedge osmotic pressure could be generated by the two-phase interface，and the microscopic cyclotron could be formed. Besides that，nano-card had enormous surface contact compared with previous spherical nanoparticles such as SiO2. Therefore，nano-card could effectively displace the remaining oil from the formation，peel off the oil film on the throat wall on micro pores，expand the sweep volume of the low permeability layer，and thus，improve the degree of the crude oil recovery.

• Optimization and Application of Strong Plugging Drilling Fluid for Horizontal Well in Tight Oil of Yanchang Oilfield

  ZHANG Wenzhe1，2，LI Wei1，2，WANG Bo1，2，LIU Yun3

  2019,36(2):191-195, DOI: 10.19346/j.cnki.1000-4092.2019.02.001

  Abstract: (2155) HTML (0) PDF (1.23 MKB)(4826)

  Abstract:

  In order to speed up the development of tight oil and improve the horizontal well drilling technology of tight reservoir in Yanchang oilfield，meanwhile，aiming at the polyacrylamide potassium salt（K-PAM）polymer drilling fluid system used in the current stage of Yanchang oilfield had shortcomings such as poor rheology，insufficient plugging and inhibition，the indoor optimization of the commonly used fluid loss reducer，inhibitor，lubricant，plugging agent and other treatment agent was preferred to obtain a formula of strong plugging type nano-polymeric alcohol water-based drilling fluid suitable for tight reservoir. Finally，the drilling fluid was applied in the field. The results showed that the polymer fluid loss additive COP-FL could significantly improve the water loss and wall-forming property of the system. The non-fluorescent anti-collapse lubricant FT342 had strong inhibition. The liquid extreme pressure lubricant JM-1 had good overall lubrication effect. And blocking agent anhydrous polymeric alcohol WJH-1 and nano-emulsion RL-2 could increase the drilling fluid blocking rate by 51.7%，which could enhance the wellbore stability. The horizontal section strong plugging type drilling fluid system，whose formula was 4% sodium bentonite，0.2% soda ash，0.4% K-PAM，2% COP-FL，1.5% FT342，1.0% JM-1，5% WJH-1 and 3% RL-2，was applied to two horizontal wells in tight reservoir of Yanchang oilfield. During the construction process，the system had good leakage prevention and sealing effect. The mechanical drilling speed increased by 30% compared with the adjacent one，the construction period shortened by 35% ，the downhole accident rate reduced by 85.7%，and the drilling cost reduced by 34.7%，which provided effective technical support for the excellent drilling of horizontal wells in tight reservoir of Yanchang oilfield.

• Common Problems and Solutions on Writing of Scientific Papers

  YANG Mingjiao，LIN Zhangbi

  2019,36(1):188-190, DOI: 10.19346/j.cnki.1000-4092.2019.01.035

  Abstract: (2816) HTML (0) PDF (1.15 MKB)(4520)

  Abstract:

  From the perspective of editorial practice，common problems in the major part of scientific paper，including abstract， introduction，experiments，result and discussion，conclusion，were analyzed. In order to improve the researchers’writing level，a method of using mind mapping to clear the writing thoughts was put forward.

• Research Progress of Imbibition Oil Production in Low-permeability Reservoirs

  LIU Kai1，2，GAO Zhendong3，WANG Chengjun1，2，GAO Yiwen1，2，MENG Xuangang3

  2021,38(4):747-753, DOI: 10.19346/j.cnki.1000-4092.2021.04.029

  Abstract: (990) HTML (0) PDF (1.36 MKB)(4286)

  Abstract:

  Through literature research，the relative concept of imbibition oil production was introduced，research results and the newest research progress of imbibition oil production method in low-permeability reservoirs were reviewed，and the development prospect of imbibition oil production in low-permeability reservoirs in lab experiments and field application was put forward.

• Research Progress on Shale Inhibitors at Home and Abroad in Recent Ten Years

  MA Jingyuan, PAN Yidang, YU Peizhi, AN Yuxiu

  2019,36(1):181-187, DOI: 10.19346/j.cnki.1000-4092.2019.01.034

  Abstract: (1896) HTML (0) PDF (1.20 MKB)(4259)

  Abstract:

  From the aspects of amine inhibitors，nanocomposites and other inhibitors，the research status of new shale inhibitors at home and abroad and some inhibitor evaluation methods were reviewed. The inhibition mechanism of various inhibitors was analyzed. In general，the hydration expansion and dispersion of shale was inhibited by various inhibitors mainly from both chemical and physical aspects，thereby improving shale stability

• Preparation and Performance Evaluation of Helper-breaking Capsule Type Shielding Temporary Plugging Protection Agent in Fracturing

  ZHANG Rusheng1，WANG Zengbao2，3，ZHAO Mengyun1，LIU Changyin1，SUN Zhiyu1，JI Yuan2，ZHAO Xiutai2

  2019,36(2):225-229, DOI: 10.19346/j.cnki.1000-4092.2019.02.007

  Abstract: (1692) HTML (0) PDF (1.32 MKB)(4252)

  Abstract:

  In order to reduce the damage to the reservoir caused by the leakage of fracturing fluid and the solid phase residue after breaking the gel，based on the shielding temporary plugging oil and gas layer protection theory and the characteristics of microcapsule breaker，the helper-breaking capsule type shielding temporary plugging protection agent in fracturing named TD-1was prepared by liquid drying method，which used organic acid as the core material，ethyl cellulose as the capsule material，polyethylene pyrrolidone as the porogen，and polyvinyl alcohol as the protective agent. The preparation condition was optimized and the performance of TD-1 was evaluated. The results showed that the main particle size of TD-1 was about 300 μm，the content of organic acid in coated core material was 34.1%，and the release rate was 69.0%，when TD-1 was synthesized under the condition of 2.0% polyvinyl alcohol，4.0% ethyl cellulose and polyvinyl pyrrolidone，and 500 r/min stirring rate. TD-1 was helpful for gel breaking of fracturing fluid，which could reduce the viscosity of fracturing fluid by 35.6% and the solid residue content by 44.9%. Meanwhile TD-1 had little effect on the viscosity of fracturing fluid and gel breaking time. TD-1 could form a temporary plugging zone on the surface of reservoir，which could reduce the invasion damage caused by the fracturing fluid filtrate and solid phase material. TD-1 improved the permeability recovery rate by 11.32% and made the core permeability recovery rate reached 82.47%，showing good effect on temporary shield plugging reservoir.

• Research Progress on Influencing Factors of Emulsion Stability with Molecular Dynamics Simulation

  WANG Zhihua1，2，XU Yunfei1，QI Xiangdong1，LIU Xiaoyu1，HONG Jiajun1

  2021,38(2):360-367, DOI: 10.19346/j.cnki.1000-4092.2021.02.028

  Abstract: (2402) HTML (0) PDF (2.17 MKB)(4112)

  Abstract:

  The stability of emulsions presents a significant challenge in surface process particularly，both in terms of crude oil dehydration and produced water treatment. Considering the potential influence of asphaltene and resin in crude oil，especially the polymer and surfactant would be appeared in actual produced emulsions in chemical flooding process. This paper reviewed the application and research progress of molecular dynamics simulation in the field of oil- water interface stability mechanism. The available methods and relevant software for characterizing the visualization，density distribution，radial distribution function，oil water interface formation energy，and molecular diffusion coefficient were discussed，respectively. In order to understand the interphase interaction of crude oil emulsions and address it，the molecular dynamics simulation could be used as an effective method according to the existed research. The review indicated that breaking through the limitations of model simplification and single factor simulation to understand the molecular adsorption，droplet coalescence，and droplet separation from micro-scale was a research application and development direction of molecular dynamics simulation in the fields of oil- water emulsification and demulsification. Furthermore，the component properties of internal phase and external phase，and the temperature and pressure conditions need to be considered.

• Research Progresses on Improving Steam-assisted Gravity Drainage Application for Heavy Oil Recovery

  SHU Zhan，PEI Haihua，ZHANG Guicai，GE Jijiang，JIANG Ping，CAO Xu

  2020,37(1):185-190, DOI: 10.19346/j.cnki.1000-4092.2020.01.032

  Abstract: (1583) HTML (0) PDF (1.02 MKB)(3732)

  Abstract:

  Steam-assisted gravity drainage（SAGD）technology is widely used in the production of ultra-heavy oil，but there are problems such as severe steam channeling and low heat utilization during the development process. By summarizing the current main technical methods to improve the development effect of SAGD，such as gas-assisted SAGD technology，solvent-assisted SAGD technology，foam-assisted SAGD technology and chemical additive-assisted SAGD technology，the mechanism of improving SAGD technology and the effect of improving recovery efficiency were introduced. The existing problems and suggestions for use were put forward. The differences between reservoir geological conditions and construction conditions should be considered comprehensively，and different auxiliary SAGD technologies should be selected to maximize the economic benefits.

• Research Progress of Enhancing Oil Recovery Mechanism by Using Nanofluids

  ZHANG Jingnan1，2，TIAN Lei3，ZHANG Hongwei1

  2021,38(1):184-190, DOI: 10.19346/j.cnki.1000-4092.2021.01.034

  Abstract: (2606) HTML (0) PDF (2.12 MKB)(3686)

  Abstract:

  Nanofluid flooding is of great significance to reduce the cost of oil development and enhance oil recovery. A series of important results have been achieved about the research on the mechanism of nano-fluid flooding. This paper focuses on the basic research related to the nanofluid flooding mechanism. And the four mechanisms of nanofluid enhanced flooding are summarized based on the different academic opinions and research results. According to this，it is pointed out that under the combined effects of structural separation pressure，rock wetting change and reduced oil-water interfacial tension，the nanofluid exhibits the dual characteristics of“roll-up”and“diffusion”in the process of oil displacement，thus having enhanced oil displacement. Finally，it is pointed out that nanofluids will have a very broad application prospect in the field of enhancing oil recovery，but a lot of research is needed on the effect and influencing factors of nanofluid flooding. In addition，the effective combination of nanofluid flooding and foam flooding is a way to enhance oil recovery.

• Status of Enhanced Oil Recovery Technology by In-situ CO₂ Generated in the Formation

  JIN Fayang，ZHOU Shunming，GAO Shibo，YAO Zheng，WANG Ruilin

  2021,38(3):564-570, DOI: 10.19346/j.cnki.1000-4092.2021.03.033

  Abstract: (887) HTML (0) PDF (1.25 MKB)(3656)

  Abstract:

  In view of the shortcomings of conventional CO₂ flooding，domestic and foreign scholars have proposed in-situ CO₂ generation technology and done a lot of research. This technology is a new technology that spontaneously produces CO₂ or foam in the reservoir to displacement oil through the interaction of chemical agents，it has the advantages of no natural CO₂ resources required，controllable gas production，simple process，good injection，and strong adaptability，it is a promising enhanced oil recovery technology. Based on in-depth research，this paper reviews the research progress on the CO₂ gas production system in recent years and the mechanism of the self-generated CO₂ flooding technology.

• Analysis of Factors Affecting Stability of Low Oil-water Ratio Emulsion

  FU Shunlong1，HOU Shanshan2，WU Yu2，YOU Fuchang2，HE Miao3

  2021,38(2):191-195, DOI: 10.19346/j.cnki.1000-4092.2021.02.001

  Abstract: (1802) HTML (0) PDF (2.48 MKB)(3566)

  Abstract:

  In order to obtain oil-based drilling fluids with stable performance at low oil to water ratios，the stability of water-in-oil emulsions is critical. The effects of emulsifier addition，organic soil addition and temperature on the stability of water- in- oil emulsion with oil-water ratio of 60/40 were analyzed by electrical stability test，static stability test and micro-morphometry. The results showed that when the addition of the emulsifier was 4% ，the emulsion droplets were fine and dispersed evenly，the demulsification voltage was the highest and the emulsion stability was the best. At the temperature of 100 ℃ and 120 ℃，the emulsion droplet size changed little，and the demulsification voltage was close，indicating that there was little difference on stability. However，when the temperature increased up to 150 ℃，the emulsion droplets augmented significantly，the demulsification voltage droped sharply，stability significantly deteriorated. When adding 2% organic soil，the emulsion droplets under 400 times objective lens were invisible to the naked eye，the demulsification voltage exceeded 400 V，and the oil separation rate was only 0.1% after standing for 25 hours，as a result，the stability was remarkably improved. Analyzing the mechanism of key materials and optimizing the amount of appropriate treatment agent were important to ensuring the stability of emulsions with low oil-to-water ratio，which had practical guiding significance for on-site oil-based drilling fluid performance maintenance.

• Field Application and the Performance of Biological Enzyme Double Breakdown Technology at High Temperature

  LIU Yi1，2，LUO Cheng1，LI Liangchuan1，2，WU Jun1，2，WU Zuohao1，YAN Fei1，2，DAN Jiamin1，2

  2019,36(3):394-399, DOI: 10.19346/j.cnki.1000-4092.2019.03.003

  Abstract: (1882) HTML (0) PDF (2.10 MKB)(3383)

  Abstract:

  Aiming at the problem of gel nonuniform breaking using ammonium persulfate（APS）at fracturing fluid in Gaoshangpu oilfield，a gene fragment of β-mannan enzyme was extracted from marine thermophilous bacteria. The gel breaking principle of APS and biological enzyme was analyzed by means of GPC and electrospray ionization mass spectrometry. The proper temperature and the range of pH vale of β-mannan enzyme was researched. The fracturing fluid prepared with guar gum，biological enzyme，capsule breaker and other additives was applied in some deep wells of Gaoshangpu oilfield. The results showed that mannan enzyme was endonuclease. The viscosity and molecular weight of guar gum were greatly reduced by intersecting action which directly affected on the glycosidic bond and mainly produced 2—6 oligosaccharides with few monosaccharide. While APS preferred to break the C—C bond on the sugar ring. β-mannan enzyme tolerated 120℃ and 4—10.5 pH value. The optimum temperature was 70℃ and the pH value was 6—7. The enzyme activity at 120℃ was 40% of the highest enzyme activity，and the activity could maintain 55 min. While when the temperature was 90℃，the activity maintaining time increased to 180 min. Adding APS and biological enzyme into the fracturing fluid could reduce 22%—45% residue content. When the fracture was completely closed，the technology of injecting high concentration biological enzyme acquired effective stimulation in 9 fractured wells. The average injection pressure initially decreased about 13 MPa，the average cumulative injection quantity was 1.2×10⁴ m³，and the validity was 290 days.

• Treatment and Reuse of Guar Gum Fracturing Flow-back Fluid Using the Technology of“Water Quality Regulation-flocculation-ozone Oxidation”

  MA Zhenpeng1，LI Hui1，YANG Zhigang1，YU Tiantian2，MA Tianqi1，ZHANG Shuxia1

  2019,36(2):215-218, DOI: 10.19346/j.cnki.1000-4092.2019.02.005

  Abstract: (1558) HTML (0) PDF (1.28 MKB)(3336)

  Abstract:

  Based on the analysis of the water quality characteristics of the guar gum fracturing flow-back fluid（GGFFBF）from acertain oil well in Yanchang oilfield，the process of water quality regulation-flocculation-O₃ oxidation was carried out to treat the GGFFBF and the treated GGFFBF was reused to prepare the slick water fracturing fluid. The effects of various process parameters on the treatment effect were explored. The results showed that when adjusting the pH value of the 500 mL GGFFBF to 9.0 and adding 800 mg/L flocculant IF-A and 1.0 mg/L coagulant FA-B，and then pumping O3 for 40 min at a speed of 30 mL/min，the treated GGFFBF was colorless，clear and transparent，and the water quality was good. The SS content was less than 3.0 mg/L，the Feion content was below 0.5 mg/L，the viscosity was reduced to 1.28 mPa·s，and the bacterial content was low. The slick water fracturing fluid was prepared with the treated GGFFBF，and the performance of the slick water fracturing fluid was similar to that of the slick water fracturing fluid prepared with tap water，according with DB.61/T 575—2013 standard. The treated GGFFBF met the requirements for water preparation for slick water fracturing fluid.

• Performance Evaluation and Application of Pressure-lowering and Injection-increasing Agent in Low Permeability Reservoir of Jidong Oilfield

  LIU Jing1，2，LIU Yi1，2，LI Liangchuan1，2，WANG Jinzhong1，2，ZHANG Xia1，2，TANG Cong1，2

  2019,36(2):271-276, DOI: 10.19346/j.cnki.1000-4092.2019.02.016

  Abstract: (1375) HTML (0) PDF (1.33 MKB)(3325)

  Abstract:

  Aiming at the problems of rapid rising of water injection pressure and under-injection during the process of water injection in Gaoshangpu oilfield，a cationic-nonionic surfactant and pressure-lowering and injection-increasing agent JDZC was designed through the physical characteristics of low permeability reservoir in Jidong oilfield. The effects of JDZC dosage on surface tension，oil-water interfacial tension and emulsifying ability，and the temperature resistance，pressure-lowering and injection increasing ability of JDZC were studied. Finally，JDZC was applied in the field. The results showed that the temperature resistance of JDZC made from polyoxyethylene ether nonionic surfactant and rosin-based triquaternary ammonium salt could reach 130℃. With the increase of JDZC dosage，the surface tension of JDZC solution decreased and stabilized gradually. The surface tension of 500 mg/L JDZC solution was 28 mN/m. The critical micelle concentration of JDZC solution prepared with injected water in Jidong oilfield was 1000 mg/L. The minimum interfacial tension between 500—5000 mg/L JDZC solution and Jidong crude oil was maintained in the order of 10^-2 mN/m. The emulsifying ability of JDZC to crude oil was good，and the larger the dosage，the stronger the emulsifying ability was. JDZC had obvious effect of reducing pressure and increasing injection for the core of Gaoshangpu main formation. The permeability of core after washing increased by 40% and the pressure decreased by 26%. The field application results of 38 wells showed that the field implementation efficiency was 94%，the initial injection pressure of water injection wells decreased by 8.5 MPa on average，the validity period was more than half a year，and the average enhanced injection of single well was more than 2×10³ m³，which improved the water injection problem of Gaoshangpu low permeability reservoir.

• Performance Evaluation of Thickener for Seawater-based Fracturing Fluid with High Temperature

  CHEN Lei，BAO Wenhui，GUO Bumin，WANG Xinzun，LI Meng，SUN Houtai

  2020,37(1):17-21, DOI: 10.19346/j.cnki.1000-4092.2020.01.004

  Abstract: (976) HTML (0) PDF (1.44 MKB)(3267)

  Abstract:

  In order to meet the demands for seawater-based fracturing fluid under the temperature of 180℃，a thickener SWF-T180 of associated polymer was synthesized with acrylamide， acrylic acid， 2-acrylamido-2-methyl-propanesulfon-icacid， N-vinylpyrrolidone， dodecanol maleic anhydride sodium and N-hexadecylacrylamide as raw material， and ammonium persulfate-sodium sulfite as initiator. The increasing viscosity，salt-tolerance，swelling，temperature-resistance of SWF-T180 and the performance of seawater-based fracturing fluid prepared by SWF-T180 were evaluated. The results showed that SWF-T180 had an obvious viscosity enhancement effect. When the dosage of SWF-T180 was greater than 0.6%，the viscosity of the fluid increased rapidly. SWF-T180 had good resistance to salt，calcium and magnesium with large dissolving capacity. The viscosity of SWF-T180 after dissolving in seawater for 8 minutes reached 84.3% of its ultimate viscosity. The temperature resistance of SWF-T180 was up to 180℃. The viscosity of seawater-based fracturing fluid composed of 1% SWF-T180 and 0.6% crosslinking agent was 60—70 mPa·s under the condition of 180℃ and 90 minutes shearing time. SWF-T180 had a good shear recovery feature，which met the requirement of offshore reservoir fracturing operation at 180℃.

• Preparation and Performance Evaluation of Cationic Polymer Chromium Gel

  XU Yuande，GE Jijiang，SONG Longfei，ZHANG Yuhao，DU Xiaojuan

  2019,36(2):230-235, DOI: 10.19346/j.cnki.1000-4092.2019.02.008

  Abstract: (1725) HTML (0) PDF (1.38 MKB)(3249)

  Abstract:

  In order to deal with the issue that high strength chromium gel always had high crosslinking speed，the formula of plugging agent was optimized by selecting cationic polymer and using of alumina sol. The chromium gel plugging agent suitable for deep profile control was developed and its performance was evaluated. The results showed that for acrylamide （AM）/ acryloyloxyethyltrimethylammonium chloride（DAC）binary copolymer organic chromium gel，the lower the cationic degree，the longer the gelation time was. Alumina sol could effectively delay the gelation time of cationic polymer chromium gel and improve its strength and long-term stability. The optimum formula of chromium gel system was 0.8% polymer Y5 with 5% cationic degree， 0.3% chromium acetate and 0.2% aluminum sol. The gelation time was 55 h at 90℃ and the elastic modulus was 16.6 Pa，which belonged to high-strength gel. The plugging agent had good injection ability and strong shear resistance. Meanwhile，it had strong temperature and salt resistance，and its blocking rate could reach more than 96%. This plugging agent had long gelation time and strong plugging performance，which could satisfy the requirements of deep profile control.

• Rheological Properties of Erucamidopropyl Dimethylamine Modified Carboxymethyl Hydroxyethyl Cellulose Solutions

  FAN Yue1，JIN Hao1，FANG Bo1，LU Yongjun2，QIU Xiaohui2，SUN Rui1

  2019,36(2):209-214, DOI: 10.19346/j.cnki.1000-4092.2019.02.004

  Abstract: (1969) HTML (0) PDF (1.78 MKB)(3248)

  Abstract:

  To improve the thickening ability and crosslinkingperformance of cellulose，widen its application in fracturing fluid field，a new kind of hydrophobic etherifying agent（3-chloro -2-hydroxypropylerucylamideammonium acetate was prepared to modify carboxymethyl hydroxyethyl cellulose （CMHEC）. Hydrophobic erucamidopropyl dimethylamine carboxymethyl hydroxyethyl cellulose （ED-CMHEC） was first prepared. The rheological and crosslinking experiments of CMHEC and ED-CMHEC were carried out. The results showed that ED-CMHEC solutions exhibited higher viscosities，more apparent thixotropy and viscoelasticity，compared to CMHEC solution. At the mass fraction of 0.3% ，the viscosity of CMHEC and ED-CMHEC solutions at the temperature of 30℃ and at the shearing rate of 170 s^-1were 18.0 mPa·s and 71 mPa·s，respectively. The shear thinning behaviors of CMHEC and ED-CMHEC solutions at different concentrations could be well described by Cross model. Under the same crosslinking conditions that the dosage of zirconium organic crosslinker was 0.2%，the viscosity of gel formed by 0.3% ED-CMHEC solution was 2.4 times than that by 0.3% CMHEC solution，which indicated that ED-CMHEC had a stronger crosslinking performance.