Oil and gas reservoirs in volcanic rocks are a particular type of unconventional reservoir and present unique challenges for exploration and production engineers. To help the oil industry understand volcanic reservoirs and solutions to complex development problems, we reviewed their key engineering technologies as well as their geological characteristics. The distinctive geological characteristics of volcanic hydrocarbon reservoirs are strong heterogeneity, low porosity and permeability, complex fracture systems, etc. The volcanic reservoir rock types in order of hydrocarbon abundance are basalt (38.5%), andesite (15.9%), volcaniclastic (12.1%), and rhyolite (11.5%). The porosity ranges from 0.1 to 70%, and permeability ranges from 0.0007 to 762 md. In some commercially developed volcanic reservoirs of China, the average porosity is 7.7–13%; the average permeability is 0.41–3.4 md. Engineers have applied a variety of adapted technologies to produce volcanic reservoir economically. Horizontal wells can increase production and reserves by 4–6 times those of vertical wells, and longer wells are preferred. Specialized hydraulic fracturing techniques are suggested, including small or mixed proppant size, second HF treatment after proppant slugging, high-viscosity frac fluid with high-temperature resistance, special fluid loss reducer, high pump pressure, Extreme Overbalance Perforating, limited-entry fracturing, matrix acidizing, etc. Water control measures include producing below critical rates, partial perforation or penetration, controlling hydraulic fracture height, using horizontal wells, implementing complete cementing job, etc. Well productivity evaluation should be conducted to understand well performance and appropriately allocate production rates among wells, using the modified AOF method and other productivity prediction models considering breakdown fracture gradient, gas slippage effect, non-Darcy effect, etc. Well sites need to be selected based on recognizing profitable lithologies, lithofacies, high porosity and permeability, relatively developed fracture systems, thick net pay zones, etc. The critical questions for the industry are how to enhance volcanic reservoir recovery with more efficient and economic hydraulic fracturing and water control techniques. This is one of the first papers systematically summarizing the engineering technologies and unique solutions to develop volcanic reservoirs. Further and more complete reviews can be carried out in the future, and more novel and effective techniques can be explored and tested in the field.

The gas–water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. This paper conducted a series of high-temperature and high-pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas–water seepage. The gas–water relative permeability was simulated in this experiment through variations in temperature, pressure, and gas composition. Temperature has a significant impact on both gas and water relative permeability, particularly on gas relative permeability. As temperature increases, gas relative permeability shows a substantial increase, while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas composition has minimal influence on the gas–water relative permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases. However, as water saturation exceeds 80%, distinctions gradually emerge. The relative permeability of nitrogen is approximately 92% lower than that of mixed gas when the bound water saturation reaches 80%. This investigation provides valuable insights into the characteristics of gas–water relative permeability in high-temperature and high-pressure condensate reservoirs within Yinggehai Basin, thereby offering significant contributions to development strategies for similar reservoirs.

The gas-water relative permeability curve plays a crucial role in reservoir simulation and development for condensate gas reservoirs. In this study, we conducted a series of high temperature and high pressure analysis experiments on real gas cores from Wells A and B in Block L of the Yinggehai Basin to investigate the effects of temperature, pressure, and different types of gas media on gas-water seepage. The experimental results demonstrate that: Temperature has a significant impact on both gas and water relative permeability, particularly on the former. As temperature increases, gas relative permeability shows a substantial increase while water relative permeability remains relatively unchanged. Under the same effective stress, increasing pressure causes downward shifts in both the gas and water relative permeability curves; however, there is a more pronounced decrease in gas relative permeability. Gas type has minimal influence on phase permeability except at higher water saturation where differences become apparent. When water saturation ranges from 80% to 50%, there is no significant variation observed in the measured relative permeability of different displacement gases; however, as water saturation exceeds 80%, distinctions gradually emerge. At bound water saturation conditions, nitrogen exhibits lower relative permeability compared to simulated gases with approximately 92% similarity between them. This investigation into the characteristics of gas-water relative permeability in high temperature and high pressure condensate reservoirs within Yinggehai Basin provides valuable insights for efficient development strategies for similar reservoirs.

Low-permeability reservoirs in the western South China Sea hold substantial hydrocarbon reserves; yet, their development via water injection remains suboptimal due to challenges such as high CO ₂ content (22–42%) in associated gas. To enhance recoverable reserves and unlock residual oil potential, this study investigates the interplay of gas–water–rock interactions during CO ₂ flooding under extreme reservoir conditions: high temperature (140°C), high pressure (33 MPa), and significant dip angles (5–20°). Laboratory experiments and mechanistic analyses were conducted to evaluate phase-state transitions of crude oil, CO ₂ -driven permeability enhancement, and recovery efficiency. Results demonstrate that CO ₂ injection induces a phase shift from liquid-dominant to gas-dominant systems, elevating the gas–oil ratio and saturation pressure while expanding the gas–liquid phase boundary. Notably, steeper reservoir dip angles synergistically amplify recovery rates, achieving a peak efficiency of 88.8 at 80% CO ₂ injection. Rock dissolution, driven by CO ₂ –water interactions, selectively dissolves feldspar (45% plagioclase) and clay minerals (22% kaolinite), enlarging pore radii (0.8 → 1.2 μm) and increasing permeability by 10%. Dynamic displacement experiments further reveal a 10% rise in gaseous-phase permeability post-dissolution. These findings highlight the dual role of CO ₂ flooding in enhancing oil recovery and enabling carbon storage, with annual sequestration potential projected at 2.5 × 10 ⁴ tons. The study provides a technical framework for optimizing CO ₂ -EOR strategies in offshore low-permeability reservoirs, offering critical insights for sustainable hydrocarbon extraction and carbon management in analogous high-temperature, high-pressure environments.

To support drilling gas influx control, saline aquifer CO₂ sequestration and CCUS development under the dual carbon goals, this study proposes a high-precision calculation method for the solubility of high-temperature, high-pressure, CO₂-rich natural gas in formation water. An activity–fugacity coupling model is established: fugacity coefficients of gas components are solved via the dimensionless Helmholtz free energy equation of state, and liquid-phase activity coefficients are characterized by the Pitzer electrolyte model. Comparative experiments with three natural gas and three formation water samples are carried out at 393.15–453.15 K and 5–100 MPa to analyze the influences of temperature, pressure, salinity and CO₂ content on solubility for model verification. The overall relative error between calculated and experimental data is below 10% (max 4.5%). Solubility rises rapidly with pressure then plateaus, declines with salinity, and grows with CO₂ content; CO₂ solubility far exceeds that of alkanes. This efficient, widely applicable model cuts engineering costs and guides safe oil-gas exploitation and CCUS deployment.

The methods for determining total organic carbon (TOC) in carbonate rocks are mainly the conventional TOC method and the montmorillonite thickening method. However, both methods suffer from organic matter loss during the measurement process and inaccuracy in determining low TOC concentrations (TOC ≤ 0.5%). In this study, carbonate rock samples from the Ordovician of the Ordos Basin and synthetic standard samples were investigated using the conventional TOC method, the montmorillonite thickening method, and a newly developed elemental analysis method based on sodium polyacrylate thickening after acid digestion. The results show that gypsum-facies carbonate rocks contain organic acid salts, whereas shoal-facies and argillaceous carbonate rocks do not develop organic acid salts. For synthetic samples spiked with small-molecule organic acid salts, the relative error of the conventional TOC method exceeds 98%; for large-molecule organic acid salts, the relative error is relatively small, below 16%. The TOC measurement error of the sodium polyacrylate thickening method is lower than that of the montmorillonite thickening method. Compared with the conventional and montmorillonite methods, when carbonate rock TOC ≤ 0.5%, the sodium polyacrylate thickening method yields TOC errors mostly ≤10%, with better stability and lower error rates. The new TOC method for carbonate rocks exhibits higher accuracy and stability in determining organic carbon content, and can more objectively reflect the total organic carbon (TOC) of samples.