Xue Yan

Trade-offs between gas expansion and delayed aquifer support complicate the joint estimation of original gas in place (OGIP) and aquifer response parameters in water-drive gas reservoirs. Here, we combine response time parameterization and analytical aquifer-state propagation under piecewise linear pressure histories with the established variable-projection principle. The OGIP and aquifer capacitance are estimated using bounded conditional linear least squares, leaving a one-dimensional nonlinear search over the response time. Synthetic tests are used to recover prescribed parameters and characterize sensitivity to pressure errors and sampling density, while approximate 95% profile likelihood confidence intervals quantify parameter uncertainty under a specified withdrawal error model. In the synthetic pressure-thinning test, retaining 60% of the noninitial pressure observations gives a response time error of −2.06% when the OGIP and aquifer capacitance are fixed. Applied to approximately 20 years of field history, the method yields an OGIP estimate 0.67% above the operator-provided reference value and a normalized root mean square error of 0.009375. The field profiles reveal compensating parameter adjustments and branches governed by active bounds. The formulation supports joint evaluation of gas volume and aquifer dynamics while making parameter compensation and the role of physical constraints explicit.

Retained water associated with water-locking can restrict gas production in heterogeneous tight sandstones, and the activity and phase stability of many surfactant treatments are reduced under high-temperature, high-salinity (HTHS) conditions. In this study, a composite surfactant formulation, CSF-1, designed to lower gas–brine capillary resistance and adjust sandstone wettability under representative reservoir constraints, is reported. Its performance was evaluated using thermal aging, surface tension and contact angle measurements, geochemical compatibility tests, laser diffraction, SEM/EDS, and core flooding combined with stagewise low-field nuclear magnetic resonance (LF-NMR). CSF-1 remained macroscopically homogeneous after aging at 170 °C in 188.314 g/L hypersaline brine and retained low gas–brine surface tension when measured at 25 °C after aging. In core flooding tests, CSF-1 increased the apparent gas permeability from 0.203 to 0.388 mD relative to the SFW-saturated water-locked state, corresponding to a 91.1% improvement. One- and two-dimensional NMR measurements provided comparative relaxation domain evidence that CSF-1 promoted the removal and redistribution of relatively mobile and weakly restricted fluid signals and reduced residual signal clustering. The shortest T₂ relaxation domains were less affected. The absence of replicate core flooding and associated LF-NMR runs, together with the non-equivalent Ref-S comparison, precludes a statistically rigorous cross-agent performance ranking. These results support the laboratory water-locking mitigation potential under the tested conditions, without implying calibrated pore-size-resolved removal or field-scale confirmation.

Taking the Zhongqiu 1 Gas Field in the Tarim Basin as an example, the heterogeneity of large-scale mono-block gas fields and their primary controlling factors have been analyzed. Based on drilling core data, well log data, scanning electron microscopy, thin-section analysis, and mercury injection experiments, combining sedimentological interpretation, research on the reservoir characteristics and variability was carried out. The results showed that: (1) The lithologic characteristics showed obvious variations among wells in the Zhongqiu 1 gas field. Specifically, the main lithology developed in the Zhongqiu 1 well is feldspar lithic sandstone, while the remaining wells predominantly consist of lithic feldspar sandstone. These differences in rock composition maturity reveal that a higher proportion of stable mineral components leads to poorer reservoir properties; (2) the main factors controlling oil and gas productivity include the variations in petrology, mineralogy, and diagenetic process characteristics. The high content of unstable mineral components and constructive diagenesis could increase reservoir porosity together. (3) Sedimentary facies of the Bashijiqike Formation in the Zhongqiu 1 Gas Field played a dominant role in the reservoir distribution. The division of sedimentary facies zones reflects variations in material composition and grain size, serving as the main material basis for reservoirs. Differences in mineral composition reflect the sedimentary environment of the reservoir. Additionally, mineral composition indicates the relationship between diagenetic processes and reservoir evolution. The high feldspar content in well ZQ1 corresponded to relatively favorable reservoir properties. The dominant feldspar type was plagioclase, suggesting that early-stage chemical weathering had undergone significant alteration. The above conclusions provided a microscopic perspective to explain the differences in oil and gas production capacity of large delta-front gas fields, serving as a geological basis for the exploration and exploitation of similar fields.