Although technical advances in hydraulically fracturing and drilling enable commercial production from tight reservoirs, oil/gas recovery remains at a low level. Due to the technical and economic limitations of well-testing operations in tight reservoirs, rate-transient analysis (RTA) has become a more attractive option. However, current RTA models hardly consider the effect of the non-uniform production on rate decline behaviors. In fact, PLT results demonstrate that production profile is non-uniform. To fill this gap, this paper presents an improved RTA model of multi-fractured horizontal wells (MFHWs) to investigate the effects of non-uniform properties of hydraulic fractures (production of fractures, fracture half-length, number of fractures, fracture conductivity, and vertical permeability) on rate transient behaviors through the diagnostic type curves. Results indicate obvious differences on the rate decline curves among the type curves of uniform properties of fractures (UPF) and non-uniform properties of fractures (NPF). The use of dimensionless production integral derivative curve magnifies the differences so that we can diagnose the phenomenon of non-uniform production. Therefore, it’s significant to incorporate the effects of NPF into the RDA models of MFHWs, and the model proposed in this paper enables us to better evaluate well performance based on long-term production data.

Understanding and controlling fluids flow at the microscale is a matter of growing scientific and technological interest. Flow enhancements of water-based nanoparticle dispersions through microscale porous media are investigated through twelve hydrophilic sedimentary rocks with pore-throat radius between 1.2 and 10 μm, which are quantitatively explained with a simple model with slip length correction for Darcy flow. Both as wetting phase, water exhibited no-slip Darcy flow in all cores; however, flow enhancement of nanoparticle dispersions can be up to 5.7 times larger than that of water, and it increases with the decreasing of pore-throat radius. The experimental data reveals characteristic slip lengths are of order 500 and 1000 nm for 3M® and HNPs-1 nanoparticles, respectively, independent of the lithology or nanoparticle concentration or shear rate. Meanwhile, the phenomenon of flow degradation is observed for HNPs-2 nanoparticles. These results explore the feasible application of using nanoparticle dispersions to control flow at the microscale.

This paper presents a three-dimensional, three-phase compositional model considering CO₂ phase equilibrium between water and oil. In this model, CO₂ is mutually soluble in aqueous and hydrocarbon phases, while other components, except water, exist in hydrocarbon phase. The Peng–Robinson (PR) equation of state and the Wong–Sandler mixing rule with non-random two-liquid parameters are used to calculate CO₂ fugacity in the aqueous phase. One-dimensional and three-dimensional CO₂ flooding examples show that a significant amount of injected CO₂ is dissolved in water. Our simulation shows 7% of injected CO₂ can be dissolved in the aqueous phase, which delays oil recovery by 4%. The gas rate predicted by the model is smaller than the conventional model as long as water is undersaturated by CO₂, which can be considered as “lost” in the aqueous phase. The model also predicts that the delayed oil can be recovered after the gas breakthrough, indicating that delayed oil is hard to recover in field applications. A three-dimensional example reveals that a highly stratified reservoir causes uneven displacement and serious CO₂ breakthrough. If mobility control measures like water alternating gas are undertaken, the solubility effects will be more pronounced than this example.