Carbon dioxide (CO2) storage in geological reservoirs faces viscous fingering, gravity override, and poor mobility control due to its low viscosity and resulting inefficient distribution and compromised storage capacity. Therefore, an urgent need arises to thicken the CO₂ and enhance its viscosity for better mobility control and uniform distribution across the reservoir. This study examines the different schemes to enhance sweep efficiency in subsurface storage. In the context of polymer-, surfactant-, and foam-based technologies, the study defines optimization for CO₂ injection and retention. Sweep efficiency is critical in maximizing reservoir usage and minimizing the risk of leakage by ensuring even dispersion of CO2. Polymers could increase CO₂ viscosity, thereby yielding better mobility control and wider reservoir coverage. Surfactants reduce interfacial tension, enabling CO₂ to invade less permeable areas, while foams act as conformance control agents, changing the flow path of CO₂ away from the high permeability and into the underused areas. The study further includes advanced materials like CO2-soluble polymers, fluorinated surfactants, and nanoparticle-stabilized foams with superior stability under high-pressure, high-temperature conditions typical of deep reservoirs. Though effective, these approaches are challenged with chemical degradation, economic feasibility and environmental consequences. The study delves into these limitations and suggests integrated approaches involving polymers, and surfactant foams for enhanced sweep efficiency. These findings are a step towards realizing surfactant efficient and sustainable carbon sequestration technologies and contribute to the efforts of the world to mitigate climate change.

Compared to traditional water-based fracturing fluids, which often result in reservoir fracturing damages, water consumption, and incomplete flowback, supercritical carbon dioxide (scCO₂) fracturing technology has gained attention from scholars as a promising anhydrous fracturing technique. This is primarily due to its unique properties such as being waterless, causing no reservoir damages, providing an excellent energy-enhancing effect, and enabling thorough backflow. In addition to improving the recovery efficiency through CO₂ injection during fracturing, scCO₂ fracturing technology also enables CO₂ geological storage. However, the low viscosity of pure CO₂ as a fracturing fluid significantly limits its productivity enhancement effect. Therefore, the identification of a suitable thickener is necessary to increase the viscosity of supercritical CO₂ fracturing fluids, consequently enhancing their reservoir reconstruction efficiency. This paper explores and discusses four types of supercritical CO₂ thickeners, namely siloxane polymers, hydrocarbon and oxygenated hydrocarbon polymers, surfactants, and fluoropolymers, through comprehensive research conducted domestically and internationally. The solubility, thickening ability, experimental conditions, and challenges associated with scCO₂ thickeners are analyzed and evaluated. Finally, the characteristics of each type of thickener are summarized, and future research directions are proposed.

The incorporation of fibers represents a crucial technique for improving the mechanical properties and other relevant characteristics of cement-based composites (CBC), including concrete, cement mortar, and oil-well cement. Especially, carbon fiber (CF) has a great potential for reinforcing oil-well cement due to its high strength, modulus, stiffness, high temperature, corrosion and fatigue resistance as well as chemical stability. There is a huge amount of waste CFs all over the world which show better perfor-mance in cement industry, while their reuse will realize waste recovery (good environment impact) and greatly reduce cost. This review paper presents the recent progress of using CF in enhancing mechanical properties of CBC. We put high emphasis on the CF surface modifica cation for reinforcing bond strength at the cement/CF interface. Comprehensive discussion with respect to effects of CF and modified ed CF on CBC properties is performed. The key properties of CBC examined in this study encompass mechanical characteristics (compressive strength, flexural strength, and tensile strength), dimensional stability (shrinkage behavior), durability indicators (water absorption and permeability), and fracture-related properties (toughness, crack resistance, and impact performance). Thus, suggestions are given for the future study and application of CF in oil-well cement.

It has been found that the rock breaking tools combination of positive displacement motors (PDM) with different output parameters (positive rotational speed and positive torque) and polycrystalline diamond compact (PDC) bits with different design features exhibits significant differences in rock breaking efficiency and stability. This indicates that studying the compatibility between PDC bit and PDM before conducting drilling process is necessary. The Φ 215.9 mm wellbore condition in Longmaxi formation was taken as an example, the positive rotational speed and positive torque exerted by Φ 197mm PDM with different number of lobes and pitch length were calculated, PDC bit with different cutting strategies were designed. Then finite element method (FEM) models considering PDM output parameters were established to study rock breaking process. Required weight on bit (WOB), required mechanical specific energy (MSE), reaction torque on bit (TOB), and vibration characteristics at near-bit position under the designed rate of penetration (ROP) were obtained. Research results showed that: (1) The energy required for PDC bit with certain design features breaking shale is not a constant value, but a value changes with rotational speed and positive torque exerted by different PDM. (2) The ability controlling vibration of PDM tends to stabilize when the number of lobes N and pitch length h exceeds 5 and 140 mm respectively in general conditions, Thus combination design parameters when N = 5, h = 140 mm were suggested to balance rock breaking efficiency and service life of drill strings. (3) Compared with other cutting strategies, when rock breaking pattern consist of “face to face” interaction and “point to point” interaction, both rock breaking efficiency and stability were higher. While when matched with this cutting strategy, N = 8 and h = 140/200 mm were recommended for PDM design instead of N = 5 and h = 140 mm obtained in most cases, which cloud minimize the loss of rock breaking efficiency and improve the axial/circumferential stability by 14.24%-17.23% and 24.93%-35.73% respectively. An integrated selection and design method of PDC bit and PDM was established and implemented, which revealed the rock breaking efficiency and stability patterns of different rock breaking tools combinations, providing theoretical support and suggestions for the integrated selection and design of PDC bits and PDM in Longmaxi formation.

During workover operations in high-pressure gas wells, heavy mud losses may occur, reducing gas production. Refracturing is an effective means to restore production. The influence of heavy mud loss on refracturing is still unclear. In this paper, split core is designed to simulate the fractures of the initial transformation, transparent sand-filled pipe is designed to simulate the sand filled fractures, and the experiment of heavy mud leakage in artificial fractures under different conditions is carried out by using the displacement device, combined with CT scanning and pressure monitoring means. The influence of heavy mud loss on permeability of artificial fracture, repeated reconstruction construction pressure and flow channel configuration in artificial fracture is analyzed. The results show that workover heavy mud (WHM) loss has the greatest permeability damage to the proppant fracture packed with large particle size, up to 97%, and the fracture permeability damage of 40/70 mesh ceramsite packing is only 0.3%-0.7%. Slit core permeability damage is the least, and the decrease range is 10%-20%. The damage of matrix core permeability measured by gas is no less than 60%. Before and after the loss of WHM, the injection pressure increases significantly, up to 80 times. Combined with the CT scan results, it is found that after WHM loss, the nitrogen blowout and refracturing incompletely remove the pollution, and there is a “pollution cage” in the fracture, which is the main reason for the high construction pressure of refracturing and low production after refracturing. The research results provide theoretical basics for the refracturing of WHM loss wells.

Enhanced geothermal systems (EGS) are crucial for accessing earth's vast geothermal potential, particularly in low-permeability formations. However, conventional EGS stimulation via hydraulic fracturing often entails high operational costs, substantial water consumption, potential environmental impacts, and risks of induced seismicity. This study presents a novel thermochemical fracturing approach to enhance EGS performance and sustainability while addressing these limitations. The in-situ exothermic reaction of sodium nitrite (NaNO₂) and ammonium chloride (NH₄Cl) was applied to a 12-inch carbonate rock sample. A specialized core flooding apparatus enabled real-time evaluation of temperature profiles, permeability, and heat transfer enhancements. The thermochemical stimulation increased permeability by 109% (from 19.01 to 39.70 mD) and enhanced heat transfer by 530%. These improvements stem from an extensive micro-fracture network generated by high-pressure nitrogen gas pulses, contrasting with larger planar fractures from hydraulic fracturing. Notably, this was achieved with only a 3.3% increase in porosity, indicating preserved rock integrity. The exothermic reaction prevented core cooling during ambient-temperature stimulation fluid injection, avoiding thermal shock. The thermochemical stimulation primarily generates nitrogen gas (N₂) and a brine solution as byproducts. The generated N₂ offers the additional benefit of providing well lifting energy, simplifying flowback operations. The novel application of thermochemical stimulation in EGS represents a promising, eco-friendly, and operationally efficient alternative to conventional EGS stimulation techniques.

Polymer flooding is a key technology for improving oil recovery in reservoirs with heavy to medium crude oil. However, the adsorption and retention of polymers in reservoir pores can cause reservoir damage. This study investigates the dynamic changes at the wellhead pressure and reservoir damage induced during polymer injection due to adsorption and retention. By integrating continuity equations, polymer flow equilibrium equations, and pore permeability damage equations, a mathematical model is proposed to calculate polymer damage. The model is discretely solved using the finite difference method, effectively simulating the reduction in reservoir porosity and permeability caused by polymer adsorption and retention, as well as the changes in wellhead pressure caused by permeability variations of reservoir and viscosity variations of polymer solutions. Numerical simulation under different injection conditions reveals that the viscosity of polymer solutions is primarily influenced by polymer concentration and Darcy velocity, showing a trend of initial increase followed by decrease radially. The extent of reservoir damage and the rate of increase in wellhead pressure of the injection well correlate positively with polymer concentration and injection volume, with significant reservoir damage concentrated within approximately 2 m around the wellbore. Considering interlayer heterogeneity, inflow is identified as the main factor causing uneven damage distribution. This research enriches the study of damage caused by injection wells and provides a new mathematical model for diagnosing such damage.

Advancing the use of natural surfactants in enhanced oil recovery is crucial for sustainable practices in the oil and gas industry. This research assesses the applicability of neem-derived natural surfactants in offshore fields, encompassing surfactant synthesis via saponification, characterization through FT-IR, SEM, and EDS, and measuring surface and interfacial tension across various conditions. Adsorption studies determined the surfactant's adsorption characteristics onto rock, and core flooding tests assessed its efficacy. Surface tension measurements in deionized water (DIW) and brine confirmed the surfactant's surface activity. As the concentration increased from 1 wt% to 6 wt%, the interfacial tension (IFT) significantly decreased from 22.5 mN/m to 7.9 mN/m, marking a 64.8% reduction. Additionally, surfactants formed micelles more efficiently in saline water, with the critical micelle concentration (CMC) dropping from 4.0 wt% in DIW to 0.9 wt%.Adsorption on limestone showed over 50% higher adsorption than sandstone, confirming stronger interactions and higher adsorption saturation. Core flooding experiments demonstrated the surfactant's effectiveness in oil and water-wet conditions. When injected into sandstone, the surfactant achieved a significant additional oil recovery of 24.6% in deionized water, compared to 10.2% in limestone. Conversely, in saline conditions, the surfactant's performance was better in limestone, achieving an additional recovery of 4.9%, whereas in sandstone, it was only 1.6%. This research offers a unique perspective on how natural surfactants perform across different rock types. The findings suggest that neem-derived surfactants hold significant promise for enhancing oil recovery in Kazakhstan's oilfields.

To solve the problem whereby an oil reservoir with applicable boundaries of the current sand-inhibiting and water-control agent is unclear, a supramolecular sand-inhibiting and water-control agent PDKM was prepared using acrylamide (AM), methacryloxyethyltrimethyl ammonium chloride (DMC), styrene (SM), and γ-methacryloyloxypropyltrimethoxysilane (KH570) as comonomers. The molecular structure of PDKM was verified by ¹H-NMR and FT-IR. On the basis of establishing an evaluation method that can screen the performance of sand-inhibiting agent at a flow rate of 100 mL/min, the oil reservoir applicable boundaries of PDKM were obtained through the evaluation of sand-inhibiting and water-control performance. The experimental results show that when the concentration of PDKM is 5000 mg/L, the oil reservoir conditions are temperature ≤ 90 °C, formation water salinity ≤ 21,249 mg/L, the degree of sand production corresponding to slight sand production and particle migration, crude oil viscosity ≤ 50 mPa·s, primary water flooding water cut ≥ 75%, and formation permeability contrast ≤ 2. The performance with respect to sand inhibiting and water control can all reach an excellent level. Therefore, the PDKM solves the problem whereby the applicability of the current sand-inhibiting and water-control agent is unclear, and provides direction for the selection of suitable products in the oilfield production site.

The effici ciency of mechanical methods in controlling water production and fine migration in reservoirs has been limited, prompting researchers to focus on developing more resilient chemical methods. However, the challenge lies in the limited resistance and stability of these chemical methods in harsh reservoir conditions. To address this challenge, a study evaluated a dual crosslinker polyethyleneimine compound as a double crosslink in hydrogel composite structures. Using FTIR techniques, the study examined the structure of hydrogel compounds with single and double crosslinkers. Microscopic imaging, including SEM and ESEM analyses, provided insights into sample morphology. Equilibrium swelling and rheological tests assessed the hydrogels' three-dimensional structure and solvent retention capacity, while TGA determined sample stability. The study confirm rmed chemical bond formation between double crosslinkers via FTIR analysis. SEM and ESEM images displayed a porous, homogeneous, three-dimensional structure. The increase in pore size in the swollen state without tearing highlighted the hydrogel's elastic and self-healing properties. TGA revealed reduced weight loss with double crosslinking at 120 ° C. Strain sweep and frequency sweep tests demonstrated enhancements in critical strain and frequency with the dual crosslinker, supporting the sample's viscoelastic behavior. The hydrogel with a single crosslink maintained linear viscoelastic behavior up to 85 ° C, while the dual crosslinked sample retained it up to 200 ° C, suitable for high-temperature conditions. Swelling tests confirm rmed the sample's ability to absorb 2000% of water under reservoir conditions. Sandpack compressive strength testing indicated a fivefold increase in strength with the dual crosslinked hydrogel composite, effectively preventing fine migration.