The behavior of SP crude oil defies the typical expectation that crude oil should exhibit lower phase inversion points (PIPs) and interfacial tension (IFT) at higher temperatures. To investigate these unique characteristics, emulsification experiments were conducted on SP oil at different temperatures. The emulsifying properties of various components of SP oil and maltene, with varying asphaltene contents, were further determined. The PIP of SP oil was observed to increase with temperature, ranging from 55 % at 50 degrees C to 85 % at 85 degrees C. Among the components of SP oil, only asphaltenes exhibited a slight resistance to the reduction of the PIP with increasing temperature. For maltene, the addition of asphaltene led to a higher PIP with increasing temperature. When the optimal mass ratio of resin to asphaltene was 5:1, the PIP increased from 65 % at 30 degrees C to 75 % at 60 degrees C. Furthermore, the interfacial properties of SP oil and its components at different temperatures were analyzed. The experimental results demonstrated that the IFT of SP oil increased with temperature. The dynamic IFT exhibited an increasing trend over time while maintaining relative stability. Among the components of SP oil, only asphaltenes exhibited an increase in IFT over time. For maltene, the addition of asphaltene resulted in an increase in IFT with increasing temperature.

The adsorption behaviors of methane(CH4), 4 ), hydrogen(H2), 2 ), and their mixtures are crucial for estimating the underground hydrogen storage(UHS) capacity in depleted shale gas reservoirs. In this study, we developed four formulated kerogen models, each representing different maturation levels of type II kerogen molecules via utilizing molecular dynamics (MD) methodologies. We investigated the adsorption characteristics of pure H2 2 and mixed gases(H2 2 and CH4) 4 ) on these kerogen models with varying gas components(0.5:0.5 to 0.9:0.1) and moisture content(0-3.0 wt percentage) through grand canonical Monte Carlo(GCMC) simulations. Our findings reveal that pure H2 2 lacks a pressure point for adsorption equilibrium below 100 MPa at ambient temperature(298K). The competitive adsorption dynamics between H2 2 and CH4 4 on kerogen models demonstrate that CH4 4 exhibits stronger selectivity at lower pressures. Yet, this selectivity diminishes compared to H2 2 as system pressure increases, indicating turning points in pressure buildup with kerogen maturity. Additionally, the presence of pre- loading H2O 2 O molecules reduces the adsorption capacity of mixed gases, particularly affecting CH4 4 more than H2. 2 . This study offers profound insights into the effect of kerogen maturity and moisture content on the interaction between H2/CH4 2 /CH 4 and kerogen at a microscopic scale.

This paper presents an analytical methodology for production forecasting of wells exhibiting boundary-dominated flow in unconventional volatile oil reservoirs. An analytical model using single-phase analogy is established to predict the production rate of a multi-fractured horizontal well under multiphase flow. Pseudo-variables are employed to linearize governing differential flow equations. Therefore, the analytical model for efficiently handling multiphase flow is essentially an advanced adaptation of existing single-phase models, in which we derive new multiphase fluid properties. To calculate the pseudo-variables accurately, we summarize accessible methods for the determination of saturation-pressure (S-P) relation and further provide an appropriate way to calculate multiphase pseudo-variables in unconventional volatile oil reservoirs based on simulation results. The simulation study indicates that the S-P relation given by constant volume depletion data for near-critical volatile oils leads to satisfactory results, and the S-P relation derived from the tank-type model is appropriate for ordinary volatile oils. The analytical solution and associated methods were validated through comparison with results from a compositional simulator; the excellent agreement during boundary-dominated flow demonstrated the accuracy of the analytical methodology. The analytical methodology can greatly reduce computation and is justified to make production forecasting in unconventional volatile oil reservoirs, this tractable methodology should be attractive to the industry.

The estimation of storage capacity is crucial for underground hydrogen storage. Shale gas reservoirs have low permeability and porosity, so it is the potential site for hydrogen storage. The study is based on the depleted shale gas reservoirs with multiple flow mechanisms (diffusion, desorption and seepage). Firstly, this paper, using Laplace transformation, point source function and Stehfest inversion, presents a semi-analytical solution for bottom-hole pressure response with hydrogen duration injection. Then we, considering the multiple flow mechanisms, deduce a material balance equation specifically for shale gas reservoirs and plot modified type curves based on the Blasingame decline analysis theory. Furthermore, we discuss the effects of different critical parameters related to hydrogen storage capacity on type curves. In the final part, we describe in detail the method of obtaining hydrogen reserves using type curves. The proposed one can estimate the hydrogen volume in fractures and matrix systems, and get the actual underground storage volume through pressure response, compared with the hydrogen storage capacity calculated by the volumetric method. This study is helpful for the hydrogen capacity estimation of shale gas underground storage on-site.

The Steam-Assisted Gravity Drainage (SAGD) technology is acknowledged in the development of heavy oils worldwide because of its high efficiency. This study is based on the Long Lake reservoir with large-scale interlayers in geovlogy. Firstly, a 3D experiment was built to evaluate the existence of different distributed interlayers on the performance of SAGD technology in consideration of its geology conditions. Our experiment investigated the effect of the equivalent area of interlayers on the behaviour of the steam chamber. The experiments were grouped into three scenarios, i.e., a) no interlayer, b) quarter-length-covered interlayer, and c) half-length-covered interlayer. The experiment observations demonstrate that the steam chamber expanding would be obstructed by the designed interlayers and then go around both sides of the interlayer to reach the top of the reservoir. The steam chamber would extend out along the top surface of the reservoir and go down until the end of production. It means that the existence of a different distributed interlayer can prolong the steady-production period and reduce the production of this period. Referring to scenario a, the EUR in scenarios b&c is decreased by 4.7% and 7.3%, respectively. Moreover, the longer distributed interlayer obstacle the propagation of the steam chamber significantly. The steady-production period in scenario c should be more extended than scenario b. Also, scenario c exhibited lower production and ultimate recovery. This study is helpful for the understanding of the effect of SAGD development on the different distributed interlayers and guiding the placing of wells on site.

根据页岩气井的现场生产情况,压裂水平井产量会迅速下降,注CO2技术是改造储层提高产量的有效手段.连续驱替与吞吐式注入作为注CO2提高页岩气采收率的两种常见方式,却在相同页岩气藏中驱替效果存在差异.为了对不同储层条件下注CO2开发方式进行优选,基于现场页岩气藏实际情况建立了双孔介质气藏机理模型,并通过建立采收率影响因素的正交试验,分析了渗透率、孔隙度、储层厚度、CH4和CO2最大吸附量以及Langmuir压力等的影响规律.将渗透率作为主控因素,划分了5个不同渗透率条件,进行直接驱替与吞吐注CO2模拟,并针对不同CO2注入驱替开发方式进行了布缝模式、井位排列、闷井时间等开发参数优化.结果表明:不同渗透率条件下两种开发方式驱替效果不同,以0.001 mD为界限,渗透率低于0.001 mD时,直接驱替效果更优;渗透率高于0.001 mD时,选择吞吐式注CO2为宜;针对连续注气,交叉布缝模式具有更高的采收率,在多井同产同注时,应将生产井置于内部;另外,吞吐式注气应该选择较短的焖井时间来节约成本获得更好的经济效益.