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Most multiphase flow separation detection methods used commonly in oilfields are low in efficiency and accuracy, and have data delay. An online multiphase flow detection method is proposed based on magnetic resonance technology, and its supporting device has been made and tested in lab and field. The detection technology works in two parts: measure phase holdup in static state and measure flow rate in flowing state. Oil-water ratio is first measured and then gas holdup. The device is composed of a segmented magnet structure and a dual antenna structure for measuring flowing fluid. A highly compact magnetic resonance spectrometer system and intelligent software are developed. Lab experiments and field application show that the online detection system has the following merits: it can measure flow rate and phase holdup only based on magnetic resonance technology; it can detect in-place transient fluid production at high frequency and thus monitor transient fluid production in real time; it can detect oil, gas and water in a full range at high precision, the detection isn't affected by salinity and emulsification. It is a green, safe and energy-saving system.

Tight oil reservoir development is faced with the key technical problem that “water cannot be injected and oil cannot be produced” yet. With the diphenyl ethers water-soluble (gemini) surfactants as water phase shell and C10–C14 straight-chain hydrocarbon compounds as oil phase kernel, a nanofluids permeation flooding system was prepared by microemulsion technology, and its characteristics and EOR mechanisms were evaluated through experiments. The system has the following five characteristics: (1) “Small-size liquid”: the average particle size of the system is less than 30 nm, which can greatly reduce the starting pressure gradient of water injection, and effectively enter and expand the sweep volume of micro-nano matrix; (2) “Small-size oil” : the system can break the crude oil into “small-size oil” under the flow condition, which can greatly improve the percolation ability and displacement efficiency of the crude oil in the micro-nano matrix; (3) Dual-phase wetting: the system has contact angles with the water-wet and oil-wet interfaces of (46±1)° and (68±1)° respectively, and makes it possible for capillarity to work fully under complex wetting conditions of the reservoir; (4) High surface activity: the interfacial tension between the system and crude oil from a tight oil reservoir in Xinjiang is 10−3–10−2 mN/m, indicating the system can effectively improve the displacement efficiency of oil in fine pore throats; (5) Demulsification and viscosity reduction: the system has a demulsification and viscosity reduction rate of more than 80% to inversely emulsified crude oil from a tight oil reservoir in Xinjiang, so it can improve the mobility of crude oil in the reservoir and wellbore. The system can be used to increase oil production by fracturing in tight reservoirs, replenish formation energy by reducing injection pressure and increasing injection rate, and enhance oil recovery by displacement and cyclic injection, providing key technical support for effective production and efficient development and recovery enhancement of tight reservoirs.

CO2-responsive smart fluids have been widely investigated in the past decade. In this article, we reported a CO2-responsive smart fluid based on supramolecular assembly structures varying from vesicles to wormlike micelles.

Cardiac fibrosis is a hallmark of various heart diseases and ultimately leads to heart failure. Although long noncoding RNA (lncRNA) SNHG20 has been reported to play important roles in various cancers, its function in cardiac fibrosis remains unclear. The expression of SNHG20 and microRNA 335 (miR-335) in heart tissues of angiotensin II-induced mice and angiotensin II-stimulated mouse cardiomyocyte cell line HL-1 were detected by quantitative real-time PCR (qRT-PCR). Cell viability was evaluated by cell counting kit-8 assay. The expression of galectin-3, fibrosis-related proteins (fibronectin, collagen IaI, and α-SMA), and apoptosis-related proteins [cleaved caspase-3 and cleaved poly(ADP-ribose) polymerase (PARP)] was detected by Western blotting. Bioinformatics prediction, luciferase reporter assay, and RNA pulldown assay were performed to determine the relationship between SNHG20 and miR-335 as well as miR-335 and Galectin-3. Gain- and loss-function assays were performed to determine the role of SNHG20/miR-335/Galectin-3 in cardiac fibrosis. SNHG20 was significantly upregulated and miR-335 was downregulated in heart tissues of angiotensin II-treated mice and angiotensin II-stimulated HL-1 cells. Downregulation of SNHG20 effectively enhanced cell viability and decreased cell size of HL-1 cells and the expression levels of fibrosis-related proteins (fibronectin, collagen IaI, and α-SMA) and apoptosis-related proteins (cleaved caspase-3 and cleaved PARP), which were induced by angiotensin II treatment. Furthermore, SNHG20 elevated the expression levels of Galectin-3 by directly regulating miR-335. Our study revealed that downregulation of SNHG20 improved angiotensin II-induced cardiac fibrosis by targeting the miR-335/Galectin-3 axis, suggesting that SNHG20 is a therapeutic target for cardiac fibrosis and hypertrophy.

The conventional foaming agents have the problems of poor adaptability and high cost during the application in different types of gas fields, especially in high temperature, high salinity, high acidic gas and high condensate oil and gas fields. In this study, the Gemini foaming agent was used as the main agent to enhance foaming and foam stability of the foaming agent, the grafted nanoparticles were used as foam stabilizer to further improve the foam stability, and the characteristic auxiliaries were added to make the foaming agent suitable for different types of gas reservoirs. Two types and six subtypes of nanoparticle foaming agents have been prepared for the main gas fields of China. The experimental evaluation results show that the overall temperature resistance, salinity resistance, H2S resistance, CO2 resistance and condensate resistance of the nanoparticle foaming agents can reach 160°C, 250 000 mg/L, 100 mg/L, 100% and 40%, respectively. The new foaming agents have been used in 8685 wells in China. Compared with conventional foaming agent, the average gas flow rate per well increased by 62.48%, the pressure difference (casing-tubing) decreased by 18.9%, and the cost dropped by 45%. The effect of reducing cost and increasing efficiency is obvious. Key words: water-yielding gas well, Gemini surfactant, nano-particle, characteristic auxiliaries, foaming agents series, drainage gas recovery

In the petroleum industry, detection of multi-phase fluid flow is very important in both surface and down-hole measurements. Accurate measurement of high rate of water or gas multi-phase flow has always been an academic and industrial focus. NMR is an efficient and accurate technique for the detection of fluids; it is widely used in the determination of fluid compositions and properties. This paper is aimed to quantitatively detect multi-phase flow in oil and gas wells and pipelines and to propose an innovative method for online nuclear magnetic resonance (NMR) detection. The online NMR data acquisition, processing and interpretation methods are proposed to fill the blank of traditional methods. A full-bore straight tube design without pressure drop, a Halbach magnet structure design with zero magnetic leakage outside the probe, a separate antenna structure design without flowing effects on NMR measurement and automatic control technology will achieve unattended operation. Through the innovation of this work, the application of NMR for the real-time and quantitative detection of multi-phase flow in oil and gas wells and pipelines can be implemented.

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To tackle the challenge of great depth, high pressure and high temperature (HPHT), low permeability and porosity, serious heterogeneity in deep oil/gas reservoirs, this paper proposed high efficiency reservoir stimulation based on temporary plugging & diverting, which can realize multi-stage stimulation to improve stimulated rock volume (SRV) without mechanical isolating tools. A series of degradable nanometer ester temporary plugging material with high temperature resistance and high strength has been developed. The feasibility of the method was tested by modeling experiment, and the performance of the plugging material was evaluated. The high efficiency stimulating technology based on chemical plugging & diverting can avoid the problems of high cost and high risk operations by mechanical isolating tools in HPHT deep wells. This technology has been applied in 211 wells from 10 deep oil/gas reservoirs in China, with average production increment per well 3.5 times higher than conventional technologies. This technology enhanced reservoirs production and stimulation effect, lowered the operation difficulty and risk, and decreased multi-stage stimulation cost for deep reservoirs. Key words: deep reservoir, reservoir stimulation, temporary plugging and diverting, high temperature resistance, high strength, degradable chemical plugging material

Aimed at the disadvantages of secondary damage to oil layers caused by the conventional bull-heading water control technique, a thermo-sensitive temporary plugging agent for water control was synthesized by water solution polymerization and applied in the field with a new secondary temporary plugging technique. The optimization and performance evaluation of thermo-sensitive temporary plugging agent were carried out through laboratory experiments. The optimized formula is as follows: (6% − 8%) acrylamide + (0.08% − 0.12%) ammonium persulfate + (1.5% − 2.0%) sepiolite + (0.5% − 0.8%) polyethylene glycol diacrylate. The thermo-sensitive temporary plugging agent is suitable for formation temperatures of 70−90 °C, it has high temporary plugging strength (5−40 kPa), controllable degradation time (1−15 d), the apparent viscosity after degradation of less than 100 mPa(S and the permeability recovery value of simulated cores of more than 95%. Based on the research results, secondary temporary plugging technique was used in a horizontal well in the Jidong Oilfield. After treament, the well saw a drop of water cut to 27%, and now it has a water cut of 67%, its daily increased oil production was 4.8 t, and the cumulative oil increment was 750 t, demonstrating that the technique worked well in controlling water production and increasing oil production. Key words: bull-heading water control technique, thermo-sensitive temporary plugging agent, secondary temporary plugging technique, thermal degradation property, reservoir protection

During gel treatments for fractures, the leak-off behavior of gelant has a great effect on the water shut-off performance of gel. Experiments were carried out using a polymer/chromium (Cr3+) gel system to explore the leak-off behavior and the water shut-off performance of gel in fractured media. Results of the gelant leak-off study show that the gelant leak-off from fracture into matrix contributes to the formation of the gelant leak-off layer during the gelant injection. Moreover, because of the gradual formation of the gelant leak-off layer along fracture, the initial leak-off ratio of gelant is relatively high, but it declines and finally levels off with the increase of the injection volume. The polymer concentration of gelant has a great effect on the chromium output in fluids produced from fractures. With the increase of the polymer concentration, the chromium concentration first decreases and then increases, and the leak-off depth of gelant into matrix is gradually reduced. Results of the water shut-off study present that the decrease of the chromium concentration inside the fracture greatly reduces the water shut-off performance after the gel formation. Therefore, because of the relatively high degree of chromium leak-off, enough injection volume of gelant is essential to ensure the sufficient chromium concentration inside the fracture and to further achieve a favorable water shut-off performance. On the premise of gel strength assurance inside the fracture, the water shut-off performance of gel gradually declines with the extension of the distance from the fracture inlet, and different leak-off degrees of gelant along the fracture are responsible for this phenomenon. Therefore, a proper degree of gelant leak-off contributes to enhancing the water shut-off performance of gel for fractures.

CO2-responsive hydrogels, using CO2 as a “green” trigger, have recently been of considerable interest. Herein, a novel CO2-responsive self-healable hydrogel is fabricated by simply mixing hydrophobically modified polyacrylamide (HMPAM) with sodium dodecyl sulfate (SDS)–N,N,N′,N′-tetramethyl-1,3-propanediamine (TMPDA) surfactant micelles. In the presence of CO2, the SDS–TMPDA spherical micelles transform into long wormlike micelles, serving as multivalent cross-linkages to bridge HMPAM chains based on hydrophobic interactions. The interpenetrating three-dimensional network induces a sol-to-gel transition, accompanied by a 360 and 400 times enhancement of the zero-shear viscosity and storage modulus, G′ (ω = 6.28 rad s−1), respectively. In additon, the sol–gel transition can be repeatedly and reversibly switched by cyclically bubbling and removing CO2 without any harm. Furthermore, the CO2-responsive hydrogel exhibits significant shear-thinning and self-healing properties, suggesting that the hydrogel is injectable and could be used as a potential plug to block CO2 gas breakthrough channels during CO2 flooding. Therefore, we believe that the presented work will enable the development of the design of CO2-responsive self-healable hydrogels and their practical applications.

To solve the problem of unloading liquid of deep gas well with high gas temperature and salinity, high concentrations of H2S gas and condensate oil, a nanoparticle foam unloading agent was developed and evaluated, and the field test was carried out. The liquid phase foam unloading agent was prepared by blending high temperature resistant anionic surfactant, high salinity and H2S resistant zwitterionic surfactant and the condensate oil resistant fluorocarbon surfactant. The nanoparticle foam unloading agent was developed by introducing silane coupling agent modified nano silica spheres into the liquid phase foam unloading agent as the solid foam stabilizer. The property of nanoparticle foam unloading agent was studied through lab experiment, and the results show that: the agent has temperature resistance as high as 150 °C, salinity resistance up to 250 g/L, H2S resistance up to 0.04%, condensate oil resistance up to 30%, which proves high foaming ability and foam stabilizing ability. The optical microscope and zeta potential results show that: the mechanism of enhancing the property of liquid phase foam unloading agent by nanoparticles lies in the fact that the nanoparticles can adsorb onto the gas-water interface to form a solid particle film, and it has the best foam stabilizing effect at the modified nano-silica sphere concentration of about 0.002%. The field test results show that: the agent has steady performance, meets the site construction requirements, and can improve the water drainage – gas recovery efficiency in gas well and reduce the cost. Key words: deep gas well, nano-particle, nano silica sphere, foam unloading agent, unloading liquid in gas well

According to the development situation of digital oilfield construction and existing problems in our country, a set of Internet of Things remote intelligent monitoring system with comprehensive functions for oil & gas fields has been successfully developed, which can comprehensively sense production objects, such as oil&water wells and oil & gas station, to realize centralized management and control of production data and equipment state information in the production command center, and use production data in real time for effective analysis. This system breaks the information island and technical barriers, establishes data bridge with CNPC information system, creates conditions and provides guarantee for tens of thousands of field engineers to implement of fine management using solid theoretical foundation and advanced technical tools, thereby saving construction investment and operation cost of oil and gas production.

Fiber-laden fluid systems have been successfully applied for reorientation fracturing in tight gas and shale gas reservoirs around the world. Although many successful cases have been reported in the literature, there is a lack of a deep understanding of the mechanical mechanism of fiber-assisted diverting fracturing. Hence, this paper presents a systematic study of the fracture diversion mechanisms of the fiber-diverting fracturing technique. A series of laboratory experiments is conducted with a real tri-axial stress simulation system. Degradable fibers are applied to large-size natural outcrop samples (300 mm × 300 mm × 300 mm) under true triaxial stress conditions. The dynamic filtration experiment to test the temporary plugging ability showed that the fractures were effectively plugged by fiber fluids. A variety of factors related to the fracture reorientation are tested and compared, including injection rate, fracture width and horizontal principal stress difference. The additional pressure drop caused by the fiber filtration cake is calculated and used to quantitatively analyze the effects on fracture reorientation. The net pressure increase is the driving force of the fracture diversion and formation of the fracture network. The conclusions were used to guide carbonate reservoir stimulations in the Tarim oil field, in northwest China. The phenomenon of fracture diversion was evident as the pumping pressure increased considerably after injecting the degradable fiber. The hydraulic fracturing treatment and production results showed substantial pressure responses and excellent hydrocarbon production.

Self-healing systems that can spontaneously repair their damage would significantly improve the safety and prolong the lifetime of man-made materials. As external energy or healing agents are required in most of the self-healing approaches, non-covalently cross-linked polymeric hydrogels with intrinsic healing nature have attracted much attention recently. We present here a P(AM-co-DMAPS) zwitterionic copolymer based self-healing hydrogel, where AM and DMAPS are acrylamide and 3-((2-(methacryloyloxy)ethyl)dimethylammonio)propane-1-sulfonate, respectively. The electrostatic interactions within DMAPS and hydrogen bonding between AM moieties contribute to the physical cross-linking of the polymer chains and self-healing ability of the hydrogel. The reported strategy represents a general and facile route to construct zwitterionic copolymer based self-healable functional hydrogels for potential applications in the field of enhanced oil recovery (EOR).

By means of instrumental test and theoretical analysis, the gelling degree, extreme gelation concentration and plugging performance of inorganic gel (OMGL) have been studied and its appearance on surface of rock skeleton has been observed. Results show that inorganic gel is formed by reaction between OMGL system and Ca2+. The higher the concentration of OMGL and Ca2+, the higher the gelling degree. When the concentration of OMGL system is 2 to 3 times that of Ca2+, the inorganic gelling degree is the most suitable, and not sensitive to temperature. Under the same core permeability, residual resistance factor increases with the increase of concentration of OMGL system. When the concentration of OMGL system is the same, residual resistance factor decreases with the increase of core permeability. There exists a reasonable matching relation between core permeability and concentration ratio of OMGL system and Ca2+. Plugging effect of cores with the same permeability can be speculated from Ca2+ concentration. The inorganic gel coats on rock surface by absorption in the form of ionic bond of “-Si-O-Si-” instead of depositing in the channels. Key words: high salinity reservoir, inorganic gel, gelation performance, gelling degree, extreme gelation concentration, plugging performance, residual resistance factor

Based on the relationship between the molecule structure of monomers and their performance, two types of polymerizable monomers with low oil/water interfacial tension have been synthesized, which coplymerizes acrylamide to synthesize a novel polymer oil displacement agent under compound initiator and low polymeric temperature. Its structure and distribution status in brine solution were characterized by infrared spectroscopy and freeze etching electron microscope. The results show that the polymer has good water solubility, viscosifying properties, salt-resistance and temperature-tolerance, shearing-resistance in brines. Due to the graft polymerization of acrylamide and the polymerizable surface-active monomers, the polymer overcomes chromatographic separation effect, and has low oil/water interfacial tension. Interfacial tension of 0.15% polymer solution (prepared in Daqing simulation brine) is around 10−1 mN/m in Daqing No.1 oil plant crude oil. Core flooding experiments show that the oil recovery of the novel surface active polymer is 5.2% higher than that of ordinary hydrolyzed polyacrylamide because of its better viscosifying performance and lower oil/water interfacial tension. Key words: oil displacement agent, polymer, interfacial tension, recovery factor