An assessment of methane gas production from natural gas hydrates: Challenges, technology and market outlook

Currently, researchers and the industry believe that water invasion into a shale matrix should dominate the process of water soaking before flowback of hydraulic fracturing fluids. Based on laboratory observations with Tuscaloosa marine shale (TMS) cores, we postulate a hypothesis that cracks are formed in shale formations during and after hydraulic fracture stimulation and that they later contribute to improved well productivity. The formation of cracks contributes to improving well inflow performance, while the cracks also draw fracturing fluid from the hydraulic fractures, reduce fracture width, and consequently lower well inflow performance. The trade-off between crack development and fracture closure allows for an optimum water-soaking time, which could potentially maximize well productivity. A mathematical model was developed to describe the dynamic propagation of cracks based on the capillary-viscous force balance. The effect of crack formation on the long-term well productivity was analyzed using a previously published mathematical model for well productivity. A combination of the crack propagation and the well productivity models for the first time provides a technique for predicting the optimum fluid soaking time before flowback of hydraulic fracturing fluids. Sensitivity analyses show that reducing the viscosity of fracturing fluid could potentially speed up the optimum water-soaking time, while lowering the water-shale interfacial tension (IFT) could potentially delay the optimum water-soaking time. Real-time shut-in pressure data can be used in the crack propagation model to “monitor” crack development and identify the optimum water-soaking time before the flowback of hydraulic fracturing fluids for maximizing well productivity and the gas/oil recovery factor.

An analytical model for predicting the productivity of Radial-lateral wells (RLW) drilled using radial jet drilling technology was developed in this work. The model assumes uniformly distributed equal-geometry laterals draining oil or gas under pseudo-steady state flow conditions within the lateral-reached drainage area. A numerical simulation and production data from three field cases of RLW were used to compare and validate the model. The result indicates that the model overestimates the well production rates for wells by 7.7%, 3.25%, and 8.8%, respectively. The error is attributed to several sources including, lack of data for well skin factor, uncertainty of horizontal permeability (k_H) in the well area, uncertainty of permeability anisotropy (I_ani), and uncertainty in bottom hole pressure (pw). Error analysis of uncertainties in k_H, I_ani, and pw showed that the model could predict productivity well with an acceptable error (10%) over practical ranges of these parameter values. Parameter sensitivity analyses showed that an increasing number of laterals, lateral length, and horizontal permeability would almost proportionally increase productivity. Well productivity is sensitive to well skin factor and oil viscosity, but not sensitive to the radius of the lateral.