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Nitrogen reduction reaction (NRR) and nitrate reduction reaction (NO3−RR) provide a potential sustainable route by which to produce ammonia, a next-generation energy carrier. Many studies have been conducted over the years, mainly emphasizing material design and strategies to improve catalytic performance. Despite significant achievements in material design and corresponding fundamental knowledge, the produced ammonia is still very limited, which makes it prone to bias. The presence of interferants (e.g., cations and sacrificial reagents), the pH of the solution, and improper analytical procedure can lead to the over or underestimation of ammonia quantification. Therefore, the selection of the appropriate ammonia quantification method, which meets the sample solution condition, along with the proper analytical procedures, is of great importance. In this review, the state-of-the-art ammonia quantification method is summarized, emphasizing the advantages, limitations, and practicality for NRR and NO3−RR studies. Fundamental knowledge of the quantification method is introduced. Perspective on the considerations for selecting the suitable quantification method and for performing the quantification process is also provided. Although non exhaustive, this focused review can be useful as a guide to design the experimental setup and procedure for more reliable ammonia quantification results.

Microbial electrochemical technologies (METs) constitute the core of a number of emerging technologies with a high potential for treating urban wastewater due to a fascinating reaction mechanism—the electron transfer between bacteria and electrodes to transform metabolism into electrical current. In the current work, we focus on the model electroactive microorganism Geobacter sulfurreducens to explore both the design of new start-up procedures and electrochemical operations. Our chemostat-grown plug and play cells, were able to reduce the start-up period by 20-fold while enhancing chemical oxygen demand (COD) removal by more than 6-fold during this period. Moreover, a filter-press based bioreactor was successfully tested for both acetate-supplemented synthetic wastewater and real urban wastewater. This proof-of-concept pre-pilot treatment included a microbial electrolysis cell (MEC) followed in time by a microbial fuel cell (MFC) to finally generate electrical current of ca. 20 A·m−2 with a power of 10 W·m−2 while removing 42 g COD day−1·m−2. The effective removal of acetate suggests a potential use of this modular technology for treating acetogenic wastewater where Geobacter sulfurreducens outcompetes other organisms.

The biogas production technology has improved over the last years for the aim of reducing the costs of the process, increasing the biogas yields, and minimizing the greenhouse gas emissions. To obtain a stable and efficient biogas production, there are several design considerations and operational parameters to be taken into account. Besides, adapting the process to unanticipated conditions can be achieved by adequate monitoring of various operational parameters. This paper reviews the research that has been conducted over the last years. This review paper summarizes the developments in biogas design and operation, while highlighting the main factors that affect the efficiency of the anaerobic digestion process. The study’s outcomes revealed that the optimum operational values of the main parameters may vary from one biogas plant to another. Additionally, the negative conditions that should be avoided while operating a biogas plant were identified.

T oilfield is the fractured-vuggy carbonate reservoir at a temperature of around 130 °C, with salinity of up to 22 × 104 mg/L. In order to solve the problem of the high water cut in the late development stage of T oilfield, we selected XN-T from 27 kinds of swelling retarding particles by testing their swelling capacity, and coated a thin film to improve its retarding swelling capacity. The mechanisms of strong water absorption and water-holding abilities of particles were analyzed by infrared spectrometry and SEM. In the core flow experiment, the plugging rate was found to be 98.42%. Finally, the injection parameters of the coated particles were optimized to maximize the water plugging and profile control ability, resulting in an optimal particle size of 0.4–0.6 mm and a mass fraction of 10%.

In this study, a mathematical model of hydrogen production from glycerol gasification in supercritical water was established based on the CFD-DEM method. The fluidization process of a supercritical water fluidized bed and the effects of bed height and feed structure on particle distribution and residence time of feedstock were analyzed. Additionally, the temperature field in the fluidized bed, the reaction rate distribution of each reaction and the influence of wall temperature on gas yields were also studied. The simulation results show that the bubble channel is easy to form along the wall at one side of the feed inlet. When the initial bed height is high, and the double symmetric feed inlet structure is used, the residence time of the feedstock is prolonged. The pyrolysis of glycerol mainly occurs in the middle and lower part of the fluidized bed reactor, and the reaction rate of the water gas shift reaction and methanation reaction are highest near the outlet, and a high wall temperature is conducive to the glycerol gasification.

In view of the difficulty of producing heavy oil from carbonate reservoirs, the surfactant SDY-1 was synthesized by homogeneous solution polymerization with a homogeneous solution polymerization technique using aliphatic amine polyoxyethylene ether (PAEn) H(OCH2CH2)nNR(CH2CH2O)nH as the raw material, epichlorohydrin as the reaction intermediate, tetrabutylammonium bromide and pentamethyldivinyltriamine as the promoters, and alkylphenol as the catalyst. Based on the analysis of reservoir fluid and rock properties, the performance of the surfactant SDY-1 was evaluated in terms of its heat resistance, its salinity tolerance, its ability to change the heavy oil–water interfacial tension and rock wettability and its oil washing efficiency. The results show that when the salinity of the formation water is 2.23 × 105 mg/L, the addition of surfactant SDY-1 can lower the super-heavy oil–water interfacial tension with an asphaltene concentration of 30.19 wt.%, which is aged at a temperature of 140 °C for 3 days, from 22.41 to 0.366 mN/m. In addition, the surfactant SDY-1 can change the contact angle of super-heavy oil–water–rock from 129.7 to 67.4° and reduce the adhesion of crude oil to the rock surface by 99.26%. The oil displacement experiment indicates that the oil washing efficiency of the surfactant SDY-1 can reach 78.7% after ageing at a temperature of 140 °C for 3 days. Compared with petroleum sulfonate flooding, the addition of SDY-1 can improve the displacement efficiency by 33.6%, and the adsorption loss is only 0.651 mg/g oil sand. It has broad application prospects for heavy oil reservoirs with high temperatures, high pressures and high asphaltene contents.

In this paper, the immiscible water-alternating-CO2 flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO2 injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO2 injection (Con-CO2) and primary depletion production (No-CO2) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO2 WAG over both Con-CO2 and No-CO2 scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO2 injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO2 injection volume, the CO2 storage efficiency is still high, more than 84% of the injected CO2 was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO2 processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO2 enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project.

The microscopic pore structure controls the fluid seepage characteristics, which in turn affect the final recovery of the reservoir. The pore structures of different reservoirs vary greatly; therefore, the scientific classification of microscopic pore structures is the prerequisite for enhancing the overall oil recovery. For the low permeability conglomerate reservoir in Mahu Sag, due to the differences in the sedimentary environment and late diagenesis, various reservoir types have developed in different regions, so it is very difficult to develop the reservoir using an integrated method. To effectively solve the problem of microscopic pore structure classification, the low permeability conglomerate of the Baikouquan Formation in Well Block Ma18, Well Block Ma131, and Well Block Aihu2 are selected as the research objects. The CTS, HPMI, CMI, NMR, and digital cores are used to systematically analyze the reservoir micro pore structure characteristics, identify the differences between different reservoir types, and optimize the corresponding micro pore structure characteristic parameters for reservoir classification. The results show that the pore types of the low permeability conglomerate reservoir in the Baikouquan Formation of the Mahu Sag are mainly intragranular dissolved pores and residual intergranular pores, accounting for 93.54%, microfractures and shrinkage pores that are locally developed, accounting for 5.63%, and other pore types that are less developed, accounting for only 0.83%. On the basis of clear pore types, the conglomerate reservoir of the Baikouquan Formation is divided into four types based on the physical properties and microscopic pore structure parameters. Different reservoir types have good matching relationships with lithologies. Sandy-grain-supported conglomerate, gravelly coarse sandstone, sandy-gravelly matrix-supported conglomerate, and argillaceous-supported conglomerate correspond to type I, II, III, and IV reservoirs, respectively. From type I to type IV, the corresponding microscopic pore structure parameters show regular change characteristics, among which, porosity and permeability gradually decrease, displacement pressure and median pressure increase, maximum pore throat radius, median radius, and average capillary radius decrease, and pore structure becomes worse overall. Apparently, determining the reservoir type, clarifying its fluid migration rule, and formulating a reasonable development plan can substantially enhance the oil recovery rate of low permeability conglomerate reservoirs.