Abstract

The reinjection technology of impurity-containing CO₂ represents a critical challenge to the safety and economic viability of carbon capture and storage (CCS) systems. This study systematically analyzes the influence patterns of impurities on CO₂ phase behavior, flow characteristics, and reinjection energy consumption through the establishment of thermodynamic phase equilibrium models, flow assurance models, and energy consumption optimization models. By utilizing the Peng-Robinson (PR) equation of state and Aspen HYSYS software, the differential regulatory mechanisms of various impurities (e.g., N₂, H₂) on CO₂ critical point shifts, phase envelope expansion, and property parameters (density, viscosity, thermal conductivity) was revealed. Through OLGA multiphase flow simulations, we quantified the low-temperature risks induced by the Joule-Thomson effect and hydrate formation potential, demonstrating that impurity-containing CO₂ exhibits 2.66 °C less throttling temperature drop compared to pure CO₂, with the critical hydrate formation temperature decreasing from 10 °C to 8 °C. For the Snohvit field case in Norway, a reinjection scheme integrating four-stage compression with interstage air cooling optimization was proposed. This high-temperature reinjection strategy (50 °C) achieved 24.8% lower total energy consumption than conventional low-temperature injection (20 °C), while recommending further efficiency improvements through waste heat recovery and intelligent control. The findings provide theoretical foundations and technical pathways for the safe transportation and efficient reinjection of impurity-containing CO₂.

Abstract

It is crucial to expose the miscible mechanism of CO2 and crude oil for the development of ultra-deep reservoirs. The influence of oil composition and electrical properties of rock surface on the miscible process of CO2 and crude oil (C7H16, C7H16S, C7H17N, C7H16O, C7H14O2, C9H20, C11H24) at 453 K and 90 MPa is investigated by using the molecular dynamics simulation. The simulation results indicate that the adsorption of CO2 and C7H16 on the calcite surface limits the diffusion of CO2 and C7H16 along the Z direction. Meanwhile, high pressure could weaken the effect of temperature on the adsorption of CO2 and C7H16 on the calcite surface. In addition, the functional group and long chain of crude oil molecules adversely affect the miscibility between crude oil and CO2. Moreover, the positively charged surface could promote the miscibility of C7H16 and CO2. The miscibility of C7H14O2 and CO2 could be facilitated in nanoslits with the same surface charges while it could be hindered in nanoslits with the opposite charges. This work could shed new light on the further research on the application of CO2 flooding in ultra-deep reservoirs.

Abstract

CO2-responsive nanoparticles are injected into the formation to enhance oil recovery by improving reservoir heterogeneity and increasing macro sweep efficiency. As the particles migrate within the pore space, their size increases with the rise in the pH of the aqueous phase. Consequently, particles cause plugging when the pH decreases. However, the lack of a suitable model for particle migration limits the optimization of particle injection. An easy-to-understand and effective description of the particle migration process is essential for making accurate predictions.
This research introduces a novel model for particle migration. First, a pore network model is used to represent the pore structure. Then, by considering changes in particle size due to pH and treating the total particle concentration as an independent variable, Markov chain theory is applied to develop quantitative relationships between the amount of plugged particles and the total number of particles. Finally, a new control model of particle migration is established, and a comparison between theoretical predictions and experimental results is provided to validate its accuracy.

Abstract

In CCUS (Carbon Capture, Utilization and Storage) technology, CO2 pipeline transportation serves as a crucial link, and its safety directly impacts the reliability of the entire industrial chain. When a CO2 pipeline leaks, the sudden release of high-pressure CO2 from the pipeline into a low-pressure environment triggers the Joule-Thomson effect. This physical characteristic creates a significant temperature difference between the leakage area and the surrounding environment. The core advantage of infrared video technology lies in its high sensitivity to temperature field distribution, enabling the clear identification of low-temperature characteristic signals in the leakage area. Therefore, this paper employs infrared video technology for data collection, utilizes image denoising methods to remove impurities from infrared images, and finally adopts the lightweight network MobileNets to detect CO2 pipeline leaks under three different operating conditions: varying temperatures and pressures, in order to enhance the accuracy of CO2 pipeline leak detection and reduce response time. Experimental verification shows that, compared with Vgg-16 and ShuffleNet_V2 models, the MobileNetV3_Large model achieves a 100% detection accuracy rate and a faster response time relative to traditional classical models. This demonstrates that lightweight network can effectively distinguish between leakage temperature and pressure differences during CO2 pipeline leakage, achieving efficient and accurate detection results that can better meet application needs. It plays a positive role in promoting and enhancing CCUS pipeline safety.

Abstract

It is imperative to acknowledge the significance of the existing single well, single-block reservoirs within the Wenliu Oilfield, as their inherent limitations hinder the establishment of a comprehensive drilling network, the extent of their productivity, and the efficient development of their potential. The imminent necessity to enhance oil recovery (EOR) rate of “three-low” (low permeability, low productivity, low efficiency) reservoirs is underscored by the prevailing challenges. The implementation of CO2 huff-and-puff (CO2 HnP)in conjunction with wells possessing a certain degree of storage capacity can yield a substantial augmentation in the recovery rate of oil. This approach is characterized by its cost-effectiveness and expeditious outcomes. Through the utilization of numerical simulation techniques, the optimization of the slug injection methods and the design of injection parameters can be achieved. This facilitates the reduction of operational periods and the attainment of enhanced recovery rates. In order to optimize the ground injection process and tubular designs, as well as the supporting anti-corrosion process, it is essential to improve CO2 HnP monitoring technology in order to guide the field application. Furthermore, the application of quantitative characterization technology of CO2 displacement leading edge is required to guide the optimization of the implementation of the plan. Finally, the formation of the CO2 HnP process should be facilitated. From 2022 to 2025, 3 well-times of CO2 HnP were conducted in single well and individual block difficult-to-produce reserves, with cumulative injection of 3655.4 t CO2 and cumulative water injection of 8350 m3 by water injection slug. Up to now, the cumulative oil increment is 1462 t and the oil exchange ratio is 0.4 t/t, a excellent level of CO2 utilization is achieved.

Abstract

In CO2 energy storage systems, the working fluid CO2 contains impurities (H2O, SOx) from capture processes, leading to severe equipment corrosion issues that threatens the system stability. In this study, we investigated the corrosion behavior of N80, 3Cr, 9Cr and 13Cr steels in water-saturated supercritical CO2 (s-CO2) with 60 ppmv SO2 at 120°C and 20 MPa to simulate the operating conditions of CO2 energy storage applications. Multi-scale test methods were employed to systematically reveal the corrosion mechanism of the materials. Uniform corrosion rates were determined using weight-loss measurements, the surface morphology of corrosion products was characterized through scanning electron microscopy (SEM), energy dispersive X-ray spectroscopy (EDS), X-ray dif-fractometry (XRD), and the characteristics of pitting corrosion was measured by laser confocal microscopy. The results showed that for uniform corrosion, the uniform corrosion rates were measured as 0.170 mm/a for N80 steel and 0.167 mm/a for 3Cr steel, indicating nearly identical corrosion behavior. In comparison, the rates significantly decreased to 0.079 mm/a for 9Cr steel and 0.015 mm/a for 13Cr steel, demonstrating the corrosion resistance enhancement with increasing Cr content. For localized corrosion, all Cr-containing steels except 13Cr exhibited a significant tendency for pitting corrosion. Specifically, for steels with Cr content below 13%wt, the maximum pitting rate demonstrated a positive correlation with Cr content. N80 steel displayed the lowest pitting factor, attributable to its highest uniform corrosion rate. For the corrosion product scales, pits and cracks were observed on the surfaces of all tested steels. XRD analysis revealed that the corrosion product films on both N80 and high-Cr (3Cr/9Cr/13Cr) steels primarily contained FeCO3, with potential presence of FeSO4·4H2O or FeSO3·3H2O. Cross-sectional EDS line scan analysis demonstrated that apart from differences in corrosion product film thickness, the structural distinction between N80 steel and high-Cr steels stemmed from a thin Cr-rich layer formed at the surface, where Cr content differences were identified. This study indicates that Cr-containing steels pose a corrosion risk under water-saturated supercritical CO2 environment with SO2 impurity.

Abstract

Shale oil reservoirs suffer from low recovery (<10%) due to ultra-tight formations. CO₂ huff-n-puff (HnP) is a promising enhanced oil recovery (EOR) technique, but its underlying mechanisms remain unclear. This study integrates nuclear magnetic resonance (NMR) experiments and numerical simulations to investigate and quantify the contributions of different EOR mechanisms.CO₂ was injected into shale cores, followed by soaking and production, while NMR tracked oil mobilization distance. Results showed that increasing soak time from 30 minutes to 24 hours extended mobilization distance from 18 mm to 42 mm and boosted recovery from 6% to 20%. A compositional simulation model, history-matched to experiments, revealed that oil swelling and dissolved gas drive dominated the recovery process. With longer soaking (5 minutes to 48 hours), oil swelling increased its contribution from 0% to 50%, while rock expansion remained below 10%. Higher soaking pressures (5-11 MPa) enhanced extraction and gas drive effects.This study provides new insights into CO₂ HnP in shale oil reservoirs and offers a robust framework for evaluating and optimizing EOR performance in ultra-low-permeability systems.

Abstract

CO2 storage with enhanced gas recovery (CSEGR) offers the dual benefits of boosting natural gas production while achieving effective carbon sequestration, presenting broad prospects for industrial application. In this study, a numerical model of CSEGR was constructed using geological data from the Dongfang 1-1 gas field in the South China Sea to assess how different injection–production schemes and reservoir conditions affect both gas recovery and CO2 storage. To further enhance predictive capabilities, a backpropagation (BP) neural network–based surrogate model was developed. The AI-driven model accurately captured the nonlinear relationships between geological and engineering parameters and the performance outcomes. Results show that gas recovery increases with CO2 injection rate and permeability, while decreasing with bottomhole pressure and porosity. Conversely, CO2 storage performance improves with higher injection rates and bottomhole pressures but declines with greater permeability and porosity. The BP neural network achieved an average prediction accuracy of 95%, highlighting its effectiveness as a reliable tool for forecasting CSEGR performance under complex reservoir conditions.

Abstract

The marine acidic gas in Zhongyuan Oilfield is mainly distributed in the Puguang gas field in northeastern Sichuan, with characteristics such as “burial permeability, high H2S and CO2 content, and strong edge and bottom water”. As the gas field development enters the middle and lat-er stages, there are problems such as continuous decrease in formation pressure, water invasion, and increasingly serious sulfur deposition. Energy supplementation effects of gas injection with flue gas, tail gas, nitrogen, and COâ‚‚. Experiments show that the production enhancement effects are comparable under different injected media; the displacement recovery efficiency of gas-displacing-gas is high, and under the condition of equal injection volume, the recovery efficiency differs by only 0.5% – 0.9%. Compared with depletion development to different abandonment pressures, gas injection can increase the recovery efficiency by 10-27 percentage points. Gas injection for energy supplementation prioritizes the production of main layers. When 0.7 PV is injected, the recovery factor basically reaches 93%. The poor layers are affected by the partial pressure and split gas volume, resulting in slow response to energy supplementation. However, their recovery factor continues to increase as the injected gas volume rises. The main mechanisms of enhanced oil recovery by gas injection in the Puguang Gas Field are energy supplementation and displacement. Capturing COâ‚‚ and reinjecting it into gas reservoirs in high-sulfur gas fields can effectively improve oil recovery, and reinjecting tail gas can reduce carbon emissions, contributing to the achievement of the “dual carbon” goals.

Abstract

The utilization of CO2 flooding for enhanced oil recovery not only represents an environmentally sustainable approach to greenhouse gas management but also serves as a critical technical strategy in reservoir development, functioning through the injection of CO2 to replenish formation energy and reduce crude oil viscosity, thereby enhancing fluid mobility. However, this process may induce reservoir damage through complex chemical-mineral reactions, including carbonation reactions with mineral dissolution, secondary precipitation blockages, and clay mineral expansion/migration. Additional detrimental mechanisms involve wettability alteration due to CO2 extraction of light components from crude oil, asphaltene deposition and organic blockage resulting from phase behavior changes during CO2-crude oil miscibility, and mechanical damage caused by exacerbated reservoir heterogeneity from CO2 viscous fingering in high-permeability zones. To address these challenges, comprehensive prevention strategies should be implemented: Reservoir adaptability evaluation must precede optimized CO2 injection scheme design through parameter optimization (e.g., pressure control, injection rate modulation, and water-alternating-gas (WAG) injection). Chemical interventions involving precipitation inhibitors, anti-swelling agents, or surfactants should be employed, complemented by pre-treatment acidizing for blockage removal and post-flushing microemulsion techniques. Given that CO2-induced reservoir damage constitutes a multifield coupling process involving chemical-mechanical-flow interactions, an integrated management strategy emphasizing proactive prevention and dynamic regulation should be adopted. This approach, grounded in thorough understanding of reservoir geological characteristics and CO2-fluid-rock interaction mechanisms, aims to achieve dual objectives of enhanced oil recovery efficiency and reservoir protection.