In this paper, a series of fracture conductivity experiments were designed and conducted by an American Petroleum Institute (API) standard fracture conductivity evaluation system. The mixing proportion of quartz sand and ceramic was optimized. By the evaluation of the proppant breakage rate and sphericity analysis of mixed proppant with different sand volume proportions (P_S), the proppant mixture conductivity evolution behavior was analyzed. Results of this study showed that the conductivity of mixed proppant was between that of pure ceramic proppant and pure quartz sand proppant under the same conditions. For 20/40 mesh mixed proppant, a small amount of ceramic (25%) in mixed proppant could obtain 1.27–3 times higher conductivity than pure sand, while 40/70 mesh mixed proppant required the addition of 50% or more ceramic. The crushing resistance of mixed proppant determined the decrease of conductivity with the increase of effective closure stresses. A logarithmic empirical model was further derived from the results, which could be used to forecast the performance of fracture conductivity at different effective closure stresses and sand volume proportions.

Summary: Gas-hydrate cuttings are conveyed upward by the drilling fluid through the outer drillpipe/wellbore annulus during the gas-hydrate-well-drilling process. The temperature profile along the wellbore during the drilling process has not been thoroughly investigated because the gas-hydrate cuttings could affect the temperature of the drilling fluid along the wellbore. As the mixture of drilling fluid and gas hydrates flows from the bottom to the surface, the methane and other hydrocarbons present in the gas hydrates would change from liquid to gas phase and further cause well-control issues. Furthermore, the bottomhole pressure would decrease and could not provide sufficient balance to the formation pressure, which could significantly increase the risk of well blowout. A numerical solution is presented in this paper to predict the temperature profile of the gas-hydrate well during the drilling process. The main considerations were the following: Hydrate cuttings entrained in the bottom of the hole would affect the temperature of the fluid in the annulus space. The entrained hydrate cuttings could affect the fluid thermal properties in the drillstring and in the annulus. Because of the Joule-Thomson cooling effect at the outlet of the nozzles, the fluid temperature at the bottom of the hole was lower than that above the drill-bit nozzles. Hence, the gas-hydrate-dissociation characteristics were considered and integrated in the proposed numerical model. The numerical model was validated by comparing the obtained data with the Shan et al. (2016) analytical model. In addition, the obtained data were also compared with the measured temperature data of a conventional well drilled in China and a gas-hydrate-well drilling record in India. Sensitivity analysis was used to evaluate the effects of the pumping rate, Joule-Thomson effect, and injection drilling-mud temperature on the annulus temperature-profile distribution. It was found that the injection drilling-mud temperature and pumping rate could affect the temperature profile in the annulus, whereas the Joule-Thomson effect could decrease the annulus temperature of the drilling mud near the bottom.

Tight oil and gas resources are widely distributed and play an important role in the petroleum industry. Due to its nanoscale pore-throat characteristics, the capillary effect is remarkable, and spontaneous imbibition is very beneficial to the development of low-permeability reservoirs. In this study, the imbibition experiments of 2D nano blackcard, nanoemulsion, and water were carried out, respectively. The pore-throat fluid distribution characteristics before and after core imbibition were analyzed with nuclear magnetic resonance technology, and the enhanced oil recovery effects of 2D nano blackcard nanoemulsion, and water were comprehensively evaluated. The results show that the final recovery factors of cores soaked in 2D nano blackcard (0.005 ωt%) and nanoemulsion (0.02 ωt%) or imbibed in water are 32.29%, 26.05%, and 7.19%, respectively. It can be found that 2D nano blackcard is the fluid with the best imbibition effect. In this work, a new type of 2D nano blackcard was proposed and identified as a functional imbibition fluid for enhanced oil recovery in tight reservoirs, providing a practical reference for the effective development of tight, low-permeability oil and gas reservoirs.