Deep tight-gas carbonate reservoirs have huge reserves, with the advantages of having clean and low-carbon characteristics in addition to being a sustainable and stable supply which leads to very high-quality green energy, despite its difficult extraction. The reservoirs are usually modified using acid fracturing before exploitation, but due to acid erosion, the continuous alteration of the mechanical properties of the reservoir rocks complicates the process of predicting the crack initiation pressure. This paper aims to address the difficulties in predicting the crack initiation pressure by conducting a series of acid-etching experiments on carbonate rock samples subjected to splitting and uniaxial compression tests. By examining the variations in the elastic modulus, Poisson’s ratio, tensile strength under distinct acid systems, and acid-etching durations and temperatures, a quantified mathematical model was developed. This model was integrated into a fracture-initiation pressure prediction framework, resulting in a practical and user-friendly tool for the acid fracture-initiation pressure prediction model, which was further demonstrated through field engineering validation. The findings reveal that the elastic modulus, Poisson’s ratio, and tensile strength of carbonate rocks exhibit an inverse relationship with acid-etching time and temperature. Extended acid fracturing durations and high reservoir temperatures are conducive to acid-fracturing transformations. The fracture-initiation pressure-prediction-model analysis disclosed that, compared to the gelled acid, the diverting acid demonstrates a more pronounced reduction in the reservoir fracture pressure under high-temperature and short-duration conditions. An acid system preference diagram was constructed to provide a theoretical foundation for practical engineering applications, delivering valuable insights for optimizing acid fracturing treatments in carbonate reservoirs to provide a boost for the green energy extraction of tight gas.
Constructing efficient and continuous transport pathways in membranes is a promising and challenging way to achieve the desired performance in the pervaporation process. The incorporation of various metal–organic frameworks (MOFs) into polymer membranes provided selective and fast transport channels and enhanced the separation performance of polymeric membranes. Particle size and surface properties are strongly related to the random distribution and possible agglomeration of MOFs particles, which may lead to poor connectivity between adjacent MOFs-based nanoparticles and result in low-efficiency molecular transport in the membrane. In this work, ZIF−8 particles with different particle sizes were physically filled into PEG to fabricate mixed matrix membranes (MMMs) for desulfurization via pervaporation. The micro-structures and physi-/chemical properties of different ZIF−8 particles, along with their corresponding MMMs, were systematically characterized by SEM, FT-IR, XRD, BET, etc. It was found that ZIF−8 with different particle sizes showed similar crystalline structures and surface areas, while larger ZIF−8 particles possessed more micro-pores and fewer meso-/macro-pores than did the smaller particles. ZIF−8 showed preferential adsorption for thiophene rather than n−heptane molecules, and the diffusion coefficient of thiophene was larger than that of thiophene in ZIF−8, based on molecular simulation. PEG MMMs with larger ZIF−8 particles showed a higher sulfur enrichment factor, but a lower permeation flux than that found with smaller particles. This might be ascribed to the fact that larger ZIF−8 particles provided more and longer selective transport channels in one single particle. Moreover, the number of ZIF−8−L particles in MMMs was smaller than the number of smaller ones with the same particle loading, which might weaken the connectivity between adjacent ZIF−8−L nanoparticles and result in low-efficiency molecular transport in the membrane. Moreover, the surface area available for mass transport was smaller for MMMs with ZIF−8−L particles due to the smaller specific surface area of the ZIF−8−L particles, which might also result in lower permeability in ZIF−8−L/PEG MMMs. The ZIF−8−L/PEG MMMs exhibited enhanced pervaporation performance, with a sulfur enrichment factor of 22.5 and a permeation flux of 183.2 g/(m−2·h−1), increasing by 57% and 389% compared with the results for pure PEG membrane, respectively. The effects of ZIF−8 loading, feed temperature, and concentration on desulfurization performance were also studied. This work might provide some new insights into the effect of particle size on desulfurization performance and the transport mechanism in MMMs.
The physical parameters of supercritical carbon dioxide (SC‐CO2) fracturing fluid are sensitive to temperature and pressure. Accurate prediction of wellbore temperature and pressure during injection is critical for the fracturing efficiency. In this paper, a transient pressure‐field model of SC‐CO2 fracturing wellbore with tubing and annulus co‐injection was established, which was adjusted to consider the Joule–Thomson effect, axial heat conduction, expansion/compression heat, and friction heat. The model predicted the variation patterns of wellbore temperature and pressure, comparing them with those under tubing injection conditions. Effects of tubing‐annulus injection ratios and endothermic mode on bottom‐hole temperature (BHT) and wellhead pressure (WHP) were analyzed in detail. Compared with pure tubing injection, co‐injection provided higher BHT and lower WHP. At constant BHP, WHP dropped with time in the processes of tubing injection or co‐injection, while the former provided a larger WHP drop. With an increase in tubing injection ratio, the difference between tubing and annulus BHT values slightly grew. When the tubing and annulus injection displacements were allocated according to their cross‐sectional area ratio, their WHP was minimal. If CO2 was assumed to absorb all the friction heat, overestimation of BHT and WHP would be observed, which was more pronounced at larger injection displacements. This study's findings are considered instrumental in the design optimization and field application of SC‐CO2 fracturing in unconventional reservoirs. © 2021 Society of Chemical Industry and John Wiley & Sons, Ltd.
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