A 4D quantitative and intelligent diagnosis method for spatio-temporal evolution of oil-gas reservoir damage types and extent includes: determining a characteristic parameter characterizing reservoir damage by each of a plurality of factors based on a spatio-temporal evolution simulation equation of reservoir damage by each of the plurality of factors; and determining an effective characteristic parameter characterizing the damage extent of the reservoir based on the characteristic parameter characterizing reservoir damage by each of the plurality of factors. The method quantitatively simulate the characteristic parameters of reservoir damage caused by the various factors and a total characteristic parameter of the reservoir damage.

A 4D quantitative and intelligent diagnosis method for spatio-temporal evolution of oil-gas reservoir damage types and extent includes: determining a characteristic parameter characterizing reservoir damage by each of a plurality of factors based on a spatio-temporal evolution simulation equation of reservoir damage by each of the plurality of factors; and determining an effective characteristic parameter characterizing the damage extent of the reservoir based on the characteristic parameter characterizing reservoir damage by each of the plurality of factors. The method quantitatively simulate the characteristic parameters of reservoir damage caused by the various factors and a total characteristic parameter of the reservoir damage.

A resin flow analysis method includes dividing a mold space model into small elements, acquiring a penetration coefficient, acquiring a flow conductance, and performing flow analysis of a resin in each of the small elements in the mold space model based on a first relational expression of the small elements of a base material portion relating to the penetration coefficient and a second relational expression of the small elements of a space portion relating to the flow conductance.

A resin flow analysis method includes dividing a mold space model into small elements, acquiring a penetration coefficient, acquiring a flow conductance, and performing flow analysis of a resin in each of the small elements in the mold space model based on a first relational expression of the small elements of a base material portion relating to the penetration coefficient and a second relational expression of the small elements of a space portion relating to the flow conductance.

This disclosure describes systems and methods to predict viscosity of heavy oil in a geological formation, even when the geological formation also contains water such as clay-bound water, using a downhole nuclear magnetic resonance (NMR) tool. The downhole NMR tools may obtain responses include distributions of a first relaxation time T1, a second relaxation time T2, or diffusion, or a combination of these. The responses of the NMR measurements that are due to water are separated from the responses of the NMR measurements that are due to heavy oil. The responses of the NMR measurements due to heavy oil are then related to likely values of viscosity of the heavy oil based on empirical or simulated measurements.

This disclosure describes systems and methods to predict viscosity of heavy oil in a geological formation, even when the geological formation also contains water such as clay-bound water, using a downhole nuclear magnetic resonance (NMR) tool. The downhole NMR tools may obtain responses include distributions of a first relaxation time T1, a second relaxation time T2, or diffusion, or a combination of these. The responses of the NMR measurements that are due to water are separated from the responses of the NMR measurements that are due to heavy oil. The responses of the NMR measurements due to heavy oil are then related to likely values of viscosity of the heavy oil based on empirical or simulated measurements.

A method may include determining time-derivative pressure data based on pressure data regarding a pump system that is performing a hydraulic stimulation operation in a geological region. The method may further include determining a moving average value based on the time-derivative pressure data and a predetermined time window. The method may further include determining a flow rate adjustment for the pump system based on the moving average value, an update interval for adjusting flow rates, and a predetermined flow rate rule. A size of the predetermined time window may be different from the update interval. The method may further include using smoothed pressure data to determine time-derivative pressure data. The method may further include determining a flow rate adjustment for the pump system based on the time-derivative pressure data derived from the smoothed pressure data.

A method may include determining time-derivative pressure data based on pressure data regarding a pump system that is performing a hydraulic stimulation operation in a geological region. The method may further include determining a moving average value based on the time-derivative pressure data and a predetermined time window. The method may further include determining a flow rate adjustment for the pump system based on the moving average value, an update interval for adjusting flow rates, and a predetermined flow rate rule. A size of the predetermined time window may be different from the update interval. The method may further include using smoothed pressure data to determine time-derivative pressure data. The method may further include determining a flow rate adjustment for the pump system based on the time-derivative pressure data derived from the smoothed pressure data.

Shear thinning fluids may be useful as calibration fluids for calibrating rheometers with bob/rotor eccentricity and at lower shear rates, which may be particularly useful for calibrating rheometers at well sites that are used for measuring the rheological properties of complex fluids (e.g., wellbore fluids like drilling fluids, cementing fluids, fracturing fluids, completion fluids, and workover fluids). Additionally, high shear rate calibrations may also be performed with shear thinning calibration fluids. Newtonian fluids may be used for high shear rate calibrations in alternate of or in addition to the shear thinning calibration fluid.

Shear thinning fluids may be useful as calibration fluids for calibrating rheometers with bob/rotor eccentricity and at lower shear rates, which may be particularly useful for calibrating rheometers at well sites that are used for measuring the rheological properties of complex fluids (e.g., wellbore fluids like drilling fluids, cementing fluids, fracturing fluids, completion fluids, and workover fluids). Additionally, high shear rate calibrations may also be performed with shear thinning calibration fluids. Newtonian fluids may be used for high shear rate calibrations in alternate of or in addition to the shear thinning calibration fluid.