Because of bad cement job quality, water is one big problem that causes reduction in oil production, higher water cut and lower eventual oil recovery. Usually the main way to solve this problem would be to use a cement nonselective water shutoff agent. But this agent has small plugging radius, big field test risk, poor resistance to acid/alkali and pollutes the formation seriously. Therefore, one effective shutoff agent which can lower pollution from the formation must be developed. Making use of a large number of experiments and hard work, the curing agent, thickening agent and solid filling material are chosen. In this way modified urea–formaldehyde resin water shutoff agent is developed. The formula is as follows: 0.1–0.35 % curing agent GH-1, 0.1–1 % thickening agent KYPQ and 10–20 % solid filling material CT-1. Its performance such as curing time, viscosity and plugging strength is also studied in laboratory. Its curing time is controllable from 12 to 1200 min and the viscosity is flexible from 30 to 10,000 mPa s. Injecting this new shutoff agent into sand packs whose permeability is 7 μm², the displacement pressure is up to 7 MPa. After maintaining at 70 °C in an oven for 8 h, the breakthrough pressure is more than 20 MPa and the plugging ratio is more than 99 %. This water shutoff agent is successfully used in 25 oil wells. Three typical wells are chosen as examples to plug channeling or bottom water. The result of pilot test shows that the cumulative quantity of oil is 14,711 tons and the water cut rises slowly.

In this study, based on existing heavy oil extraction technology, combined with the mineral composition in a reservoir, the synergistic catalytic effect of reservoir minerals and exogenous catalysts under the reaction system of a hydrogen-rich environment not only reduces the viscosity of thick oil but also reduces the extraction cost and further improves the recovery rate of heavy oil. In this study, the impacts of different reservoir minerals and exogenous catalysts on the aquathermolysis of heavy oil were investigated. The research results showed that the sodium montmorillonite within the reservoir minerals exhibited an optimal catalytic effect, and the synergistic catalytic effect of sodium montmorillonite and catalyst C-Fe (catechol iron) resulted in a viscosity reduction rate of 60.47%. Furthermore, the efficiency of different alcohols as hydrogen donors was screened, among which ethanol had the best catalytic effect. Under the optimal reaction conditions, the viscosity reduction rate after the addition of ethanol was 75.25%. Infrared spectroscopy, elemental analysis, thermogravimetry, and differential scanning calorimetry were used to study the changes in heavy oil before and after hydrothermal cracking. Element analysis showed that the synergistic catalytic effect of sodium-based montmorillonite and catalyst C-Fe increased the hydrocarbon ratio from 0.116 to 0.117, and the content of S and N elements decreased. This fully confirms the catalytic effect of sodium-based montmorillonite and C-Fe catalyst for he hydrogenation reaction of the unsaturated carbon in heavy oil.

Modified starch and other natural polymer materials have found extensive applications in drilling fluids. However, conventional modification methods offer limited scope for further enhancing their temperature resistance, typically with the applicable temperature being below 140 °C. This paper presents the preparation of composite plant phenols using walnut shells, peanut shells, straw, and lignin, which are rich in the fundamental “three elements” of plants. To explore the improvement of the temperature resistance of cellulose-based drilling fluid additives, this study investigated the apparent viscosity, dynamic shear force, filtration performance, and adhesion coefficient of water-based drilling fluids supplemented with composite plant phenols. Additionally, the mechanism of action of the composite in drilling fluids was analyzed via infrared spectroscopy. The results revealed that the combined use of starch and composite plant phenols elevated the temperature resistance limit of starch from 160 °C to 180 °C. After aging at 180 °C, the filtration loss of the drilling fluid formulation containing composite plant phenols dropped to 3.6 mL, while the apparent viscosity climbed from 3.1 mPa·s to 13.6 mPa·s. This clearly demonstrates the excellent high-temperature resistance and filtration-reducing capabilities of composite plant phenols. When the addition of cassava starch was 2%, the filtration loss of the drilling fluid system reached a minimum of 6.2 mL. A positively charged gel was identified as the optimal high-temperature-resistant cutting agent. At a dosage of 1%, the dynamic plastic ratio of the formulation increased from 0.51 to 2.11. Tannin extract emerged as the ideal high-temperature-resistant and environmentally friendly drilling fluid treatment agent. After its addition, the apparent viscosity of the drilling fluid system increased from 2.4 mPa·s to 7.3 mPa·s, and the filtration loss decreased from 140 mL to 14.6 mL.

Long-term water flooding development has exacerbated reservoir heterogeneity, and traditional polymer gels are unable to simultaneously meet the requirements of high injectability and strong plugging strength. If the viscosity of the polymer is high, its injectability will be poor; on the contrary the viscosity is low, the plugging strength will be poor, which severely restricts the oil recovery effect. This study synthesized an NBAP through free radical polymerization followed by a substitution reaction, and a plugging system (NBAP-B1) was subsequently formed by combining the polymer with a Cr³⁺ crosslinking agent. Rheological experiments demonstrated that the system exhibited significant shear thinning behavior, as well as excellent temperature and salt resistance. Gelation experiments indicated that the NBAP-B1 system featured controllable gelation time (20~150 h) and high gelation strength (J grade), along with excellent resistance to both high temperature and high salinity. Microscopic analysis revealed that the gel formed by NBAP-B1 possessed a dense and uniform three-dimensional network structure. Injection and plugging experiments demonstrated that NBAP-B1 exhibited optimal injectability and outstanding plugging performance. Additionally, profile control and displacement tests revealed a 18.37% enhancement in oil recovery efficiency by water flooding after the application of NBAP-B1 for conformance control. Collectively, these results demonstrate that the NBAP exhibits significantly superior performance compared to single component systems. It combines excellent injectability with high strength plugging capability, offering an effective approach for enhancing oil recovery in low permeability reservoirs.

In the field of enhanced oil recovery in low-permeability reservoirs, the application of nanomaterials has attracted widespread attention. However, conventional nanomaterials exhibit issues such as large particle size and poor dispersion stability. This study selected SiO₂ nanoparticles with a particle size of 10 nm and combined them with 12 types of commonly used oilfield surfactants. After aging at 120 °C for 48 h, using dispersion stability and interfacial tension (IFT) as evaluation criteria, hexadecyltrimethylammonium bromide (CTAB) was ultimately identified as the optimal modifier. The structure and morphology of the SiO₂ particles were characterized in detail using X-ray diffraction (XRD), Fourier-transform infrared spectroscopy (FT-IR), and transmission electron microscopy (TEM). The system evaluated the dispersion stability of nanofluids before and after modification, as well as the interfacial properties (IFT reduced to the 10⁻¹ mN/m range) and wettability (oil-wet surfaces reversed to strongly water-wet, with contact angles decreasing to 30°) of nanofluids with different modification degrees. Considering economic factors, the modified nano-SiO₂ system with a ratio of 1:0.5 was selected. Microvisualization experiments revealed that the modified nanoscale system achieves residual oil displacement through three mechanisms: emulsification (reducing residual oil droplet size to enhance mobility), wetting reversal (lowering contact angle to weaken adhesion), and structural separation pressure (counteracting capillary forces to destabilize residual oil). Displacement experiments reveal that in rock cores with permeability ranging from 1 to 100 mD, the modified system exhibits a recovery rate trend that initially increases and then decreases. Nevertheless, it consistently enhances recovery rates, maintaining them above 12%, demonstrating strong application potential.

It is easy to pollute formation using the conventional method of plug channeling when the oil well cement quality is bad. To solve the problem of formation pollution, one new oil layer diverting agent-micro bubble treatment fluid is developed. It cannot reverse rock wettability and cannot stop reservoir fluid flowing. The properties of rheology, static plugging, and dynamic pollution of micro bubble treatment fluid were evaluated. The laboratory experiment proved that the fuzzy-ball micro bubble treatment fluid has good injectability and its viscosity decrease with shear rate. Under the temperature of 120 °C, back pressure of 0.5 MPa and differential pressure of 5 MPa, the leakage of micro bubble was zero. Core permeability recovered ratio was up to 96.1 % after pollution for 48 h. The new fluid has been used on four wells in Jidong Oilfield. The results of pilot test showed that the effect of decreasing produced water and increasing oil production was very obvious. The cumulative quantity of oil was 12,435 t; the cumulative decreased quantity of water was 32,496 cubic meters and the average water cut had decreased by 17.6 %. The application effect indicates that it not only can reduce the operating risk but also has good plug channeling and layer protecting effect. After it is used on spot, the effect of increasing oil production and reducing aquifer yield is obvious, and the period of validity is longer.