Hao Liang

High-CO₂ natural gas reservoirs present a dual challenge: recovering methane economically while retaining CO₂ securely. The capacity of overlying saline aquifers to combine in situ CO₂ retention with CH₄ recovery remains poorly quantified. This study proposes a CO₂ retention-assisted gas recovery scheme for Block D in the Yinggehai Basin. The upper T18A saline aquifer serves as the retention interval, and a lower high-pressure interval supplies CO₂–CH₄ mixed gas. A CMG-GEM compositional model incorporating gas–water relative permeability hysteresis was used to evaluate aquifer pressure, injection–production well spacing, gas source interval, reinjection strategy, and component migration over 30 years. Depleting the T18A pressure to below 1 MPa strengthened self-driven migration; after 30 years, aquifer pressure increased by approximately 3 MPa, compared with 0.5 MPa under the original approximately 9 MPa condition. CO₂ migrated more slowly than CH₄ because of dissolution and residual trapping. A well spacing of 3–5 km delayed CO₂ breakthrough while maintaining CH₄ supply. Direct connection to the Huangliu Formation aquifer induced upward water channeling and weakened gas mobility. By contrast, produced-gas reinjection avoided this effect and yielded 9.3 × 10⁹ gmole (approximately 2.1 × 10⁸ m³ at standard conditions) of cumulative gas production by 2055, nearly one order of magnitude above self-driven injection. Reinjection from the Y2 II gas group increased cumulative CH₄ production by 76–80% relative to the A5 interval. These results provide a practical operating window for coordinating methane recovery with subsurface CO₂ retention.

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 lack of ultra-high temperature and ultra-high pressure (U-HTHP) experimental devices makes the data of CO₂-CH₄ solubility and exsolution insufficient under U-HTHP conditions, which leads to an unclear competitive solubility-exsolution mechanism of CH₄-CO₂ miscible natural gas. This study systematically investigates fluid-phase characteristics in the LD10-X gas field, the impacts of mixing ratio, sequence, temperature, and pressure on CO₂/CH₄ solubility, and the CO₂/CH₄ exsolution patterns. Mixing ratio experiments showed that CH₄ does not appear in the mixed solution when CO₂ mole fraction exceeds 7%. Solubility sequence tests revealed that CH₄ is no longer dissolved when CO₂ reaches solubility equilibrium. However, CO₂ continues to dissolve when CH₄ reaches the solubility equilibrium. Solubility with temperature and pressure experiments showed that solubility of both CO₂ and CH₄ increased with rising temperature and pressure. In addition, the exsolution amount increased slowly and then increased rapidly with the increase in the pressure difference for the CO₂ in the CO₂ and CH₄ phase. In addition, these laws were employed to explain the changes in CH₄ and CO₂ concentrations during the drill steam testing of wells LD10-X-10 and LD10-X-12, mainly because the extraction capacity of CO₂ decreased after pressure reduction. Additionally, CO₂ produced by chemical equilibrium movements extracted excess CH₄ again. This study provides guidelines for the design of CO₂ storage schemes and enhanced CH₄ recovery.

The influence of supercritical CO2 on natural gas dissolution-exsolution mechanisms under high-temperature and high-pressure (HTHP) reservoir conditions remains insufficiently investigated, affecting reserve evaluation accuracy. This study systematically investigates fluid-phase characteristics in the LD10-X gas field, impacts of mixing ratio, sequence, temperature, and pressure on CO2/CH4 solubility, and CO2/CH4 exsolution patterns. Mixing ratio experiments showed CH4 will not appear in mixed solution when CO2 mole fraction exceeds 7%. Solubility sequence tests revealed CH4 will be no longer dissolved when CO2 reached solubility equilibrium. However, CO2 will continue to be dissolved when CH4 reaches the solubility equilibrium. Solubility with temperature and pressure experiments showed that solubility of both CO2 and CH4 increased with rising temperature and pressure. In addition, exsolution amount increased slowly and then increased rapidly with the increase of the pressure difference for the CO2 in the CO2 and CH4 phase. Besides, these laws were employed to explain the changes in CH4 and CO2 concentrations during the drill steam testing of wells LD10-X-10 and LD10-X-12, mainly because the extraction capacity of CO2 decreased after pressure reduction. Additionally, CO2 produced by chemical equilibrium movements will extract excess CH4 again. This study provides guidelines for the evaluation of CO2 geological storage abundance.

Perforating as a widely-applied stimulation technology is becoming incrementally important in unconventional oil/gas development. It can effectively improve deep-lying high-temperature, high-pressure (HTHP), low-porosity, low-permeability reservoirs, eliminate near-wellbore surface pollution, and increase drainage area. Characteristics of damage zone porosity directly reflect perforating performance. To study porosity and permeability of damage zone in sandstone targets, the paper collected sandstone cores from the 3^rd section of the Zhuhai Formation to conduct a simulation experiment for HTHP perforation of large-size targets. After the simulation experiment, an automatic scanner was used to find the planar distribution of the porosity and permeability parameters of the 150°C perforation holes in the cores. The study led to two findings. First, the temperature has a minor effect on the hole depth and diameter in a specified scope. The hole depth decreases as the negative pressure increases and the depth decreases as the effective stress increases. Second, a UHP perforated sandstone target is remarkably zone-specific in planar distribution of the hole porosity and permeability. The damage zone can be divided into the fracture zone, the transition zone, the compaction zone and the undisturbed zone. Besides, the zone permeability damage was quantified. These findings can effectively support research on numerical value simulation for HTHP perforation holes. Besides, they can support HTHP well perforating design and improve near-wellbore permeability enhancement and plug removal.