Preparation and Performance Evaluation of Temperature-Resistant and Salt-Resistant Gels.

In order to improve the plugging performance of high-temperature and high-salt oil reservoir plugging agents, this paper utilizes a copolymer composed of acrylamide and 2-acrylamide-2-methylpropanesulfonic acid (AM/AMPS) as the polymer, polyethyleneimine as the cross-linking agent, and nylon fiber as the stabilizer to develop a high-temperature- and high-salt-resistant gel system. This study analyzed and evaluated the temperature resistance, salt resistance and blocking performance of the gel system. The evaluation results show that the gel-forming strength of this gel system can reach an H level, and it has good thermal stability at the high temperature of 130 °C. At the high salinity of 240,720 mg/L, the syneresis rate remains below 2.5%, and the gel-forming time is greater than 15 h; the higher the temperature, the shorter the gelling time. The results of our sand-filled pipe-plugging experiment show that the gel system can adapt to sand-filled pipes with different levels of permeability, and reaching a plugging rate of 94%.

Numerical Simulation and Parameter Optimization for Water-to-CO2 Flooding in a Strongly Water-Sensitive Reservoir.

Carbon dioxide flooding can accelerate the development of low-permeability reservoirs of the Kexia group in the K region of the T oil field, thus resolving the issue of inadequate water drive effects. This study was focused on the well group 80513 in the K region, and based on the reservoir and fluid parameters, a simulation model of water-sensitive post-CO2 flooding was constructed to refine the gas injection strategy gradually. The injection rate of the continuous gas injection stage was preferred based on the degree of recovery. Multiindicator and multifactor injection and extraction schemes were established to optimize and analyze the key controlling factors, including the gas injection rate, gas injection period, gas-to-water ratio, and bottom-hole flow pressure, in the carbon dioxide gas-to-water alternation process. Recovery efficiency, oil exchange rate, formation pressure, and carbon dioxide storage rate were used as indicators. After 5 years of continuous CO2 flooding, the results indicated that switching to CO2 gas-water alternating flooding was more appropriate for the target block's environment. The best development plan was achieved when the gas injection rates were 1.0 and 1.25 × 104 m3·d-1 for continuous gas injection and CO2 gas-water alternating flooding, respectively, with a gas-water ratio of 1:1, a gas injection cycle of 90 days, and a bottom-hole flow pressure of 25 MPa in the production wells. A comparison between the results revealed that the formation pressure and oil recovery efficiency of this well group significantly increased upon CO2 flooding, and the parameter optimization results were well suited for controlling the gas flurry, offering a versatile model for future development of the block.

Preparation and Performance Evaluation of a Self-Crosslinking Emulsion-Type Fracturing Fluid for Quasi-Dry CO2 Fracturing.

Quasi-dry CO2 fracturing technology is a new CO2 fracturing technology that combines liquid CO2 fracturing (dry CO2 fracturing) and water-based fracturing. It uses a liquid CO2 system containing a small amount of water-based fracturing fluid to carry sand, and it is characterized by sand blending at normal pressure, convenient preparation, the integrated application of resistance reduction and sand carrying, and no dedicated closed sand blender requirement. We developed a self-crosslinking emulsion-type water-based fracturing fluid (ZJL-1), which contained ionic bonds, hydrogen bonds, van der Waals forces, and hydrophobic associations, for quasi-dry CO2 fracturing, and the comprehensive properties of the ZJL-1 fracturing fluid were evaluated. The results showed that the ZJL-1 fracturing fluid had obvious viscoelastic characteristics, a heat loss rate of less than 10% at 200 °C, a good thermal stability, sufficient rheology under high temperature and high shear conditions, and a good thermal stability. The resistance reduction rate reached 70%, which demonstrates a good resistance reduction performance. Compared with conventional guar fracturing fluid, ZJL-1 can carry more sand and has a lower core damage rate. The on-site use of quasi-dry fracturing showed that optimizing the mixing ratio of liquid CO2 fracturing fluid and ZJL-1 fracturing fluid effectively enhanced oil and gas recovery. This can be used to optimize quasi-dry fracturing and can be used as a reference.

Synthesis and Performance Evaluation of a Novel Nanoparticle Coupling Expanded Granule Plugging Agent.

This study focuses on the characteristics of fractured and vuggy high-temperature and high-salt reservoirs in the Tahe Oilfield. The Acrylamide/2-acrylamide-2-methylpropanesulfonic copolymer salt was selected as a polymer; the hydroquinone and hexamethylene tetramine was selected as the crosslinking agent with a ratio of 1:1; the nanoparticle SiO2 was selected, and its dosage was optimized to 0.3%; Additionally, a novel nanoparticle coupling polymer gel was independently synthesized. The surface of the gel was a three-dimensional network structure, with grids arranged in pieces and interlaced with each other, and the structure was very stable. The SiO2 nanoparticles were attached to the gel skeleton, forming effective coupling and enhancing the strength of the gel skeleton. To solve the problem of complex gel preparation and transportation, the novel gel is compressed, pelletized, and dried into expanded particles through industrial granulation, and the disadvantage of the rapid expansion of expanded particles is optimized through physical film coating treatment. Finally, a novel nanoparticle coupling expanded granule plugging agent was developed. Evaluation of the performance of the novel nanoparticle coupling expanded granule plugging agent. With an increase in temperature and mineralization, the expansion multiplier of granules decreases; aged under high-temperature and high-salt conditions for 30 days, the expansion multiplier of granules can still reach 3.5 times, the toughness index is 1.61, and the long-term stability of the granules can be good; the water plugging rate of granules is 97.84%, which is superior to other widely used particle-based plugging agents.

Structure and histochemistry of the stem of Dracaena cambodiana Pierre ex Gagnep.

Dracaena cambodiana Pierre ex Gagnep is an important plant resource for producing dragon's blood and one of most popular ornamental trees in China. For a better understanding of the physiological function of the stem, the structural characteristics and main substance histological location of the stems of D. cambodiana were studied. The structural characteristics of the different developmental stages of stems of D. cambodiana were observed and described detailly. And then a schematic diagram of the mature stem was created. Histochemical staining showed that two kinds of polysaccharides distributed in parenchymal cells. Saponins distributed mainly in ground tissue and phenolic compounds distributed mainly in the thick cell walls. An abundant of calcium oxalate raphide bundles were identified in cortex and primary tissue. Finally, the role of the above results in the taxonomy of Dracaena species and in their strong adaptability was discussed.

Synthesis and Performance Evaluation of a Novel Heat and Salt-Resistant Gel Plugging Agent.

Tahe oil field is a typical fissure cave carbonate reservoir with a temperature of up to 120~140 °C and a total salinity of formation water of (20~25) × 104 mg/L. In this paper, AM/AMPS was selected as the polymer, 1, 5-dihydroxy naphthol as the cross-linking agent, and polypropylene fiber as the system stabilizer to synthesize a novel gel plugging agent independently; the gel has good thermal stability at a high temperature of 130 °C and increased salinity of 20 × 104 mg/L, and has a dense and relatively stable three-dimensional network structure under a scanning electron microscope. The performance evaluation of the gel plugging agent indicated that: the gel dehydration rate increased gradually with the increase in temperature and salinity, making it suitable for reservoirs with temperatures below 140 °C and formation water salinity below 250,000 mg/L; the viscosity of the gel bulk was 125.3 mPa∙s, the post-gelatinizing viscosity was 42,800 mPa∙s, and the gelatinizing time at 120 °C, 130 °C and 140 °C was 10-20 h, 8-18 h, and 7-16 h, respectively.