Guoqiang Xing

Summary: Hydraulic fracturing is an essential technology for improving reservoir permeability and enhancing gas well productivity. The experiments have confirmed that it is feasible to operate hydraulic fracturing in gas hydrate reservoirs. Consequently, clarifying the impact of hydraulic fracture on gas well productivity has been a crucial issue in developing a gas hydrate reservoir. This study established a numerical simulation model based on the embedded discrete fracture model (EDFM) for developing the gas hydrate reservoir using a fractured vertical well. To verify the accuracy of the newly-developed numerical simulation model, the local grid refinement method is used to simulate the hydraulic fracture with an arbitrary angle and the comparison results show that the numerical solution in this work is consistent with the solution from the commercial software. Subsequently, we evaluate the influence of the distance between the vertical well and fracture, hydrate saturation, well asymmetry factor, and natural fractures on the distributions of gas flow rate between matrix and fracture, field maps, and gas well productivity. The simulation results show that hydraulic fracturing can increase the initial daily gas production rate by 13.4 times which is favorable for enhancing gas recovery in gas hydrate reservoirs. The gas flow rate between the matrix and hydraulic fracture which can be significantly influenced by the well asymmetry factor (Ix) shows a U-shaped distribution for the scenarios of Ix = 0. Notably, thermal convection can exert a more significant influence on the temperature distribution inside the hydraulic fracture and a huge decrease in temperature caused by thermal convection will inhibit the decomposition of hydrate. In addition, natural fractures connected with the hydraulic fracture can arouse a more important impact on distributions of field maps and gas well productivity in a gas hydrate reservoir than unconnected natural fractures. The maximum gas flow rate occurs at the intersection of the natural and hydraulic fractures. As the angle between natural and hydraulic fractures (θf) is increased from 0° to 45°, a value of 24.93% increase in the cumulative gas production indicates that a higher value of θf is more favorable for developing gas hydrate reservoirs. This work provides a comprehensive understanding of developing gas hydrate reservoirs using a fractured vertical well in the future.

Summary: Due to the low porosity and permeability of the shale matrix, multi-fractured horizontal well (MFHW) is one of the most well-known technologies to promote the withdrawal of shale oil. It is a great challenge to characterize the flow behavior by coupling pre-Darcy flow in pores of the shale matrix and Darcy flow inside fractures, particularly in the radial composite shale reservoir with stimulated reservoir volume (SRV). Because the semi-analytical method can contribute to revealing the flow mechanism of the MFHW, the approach to efficiently obtain a suitable and exact semi-analytical solution becomes a key issue. In this work, to couple the modified point-source solution of the shale matrix with the numerical solution of fractures,we developed a semi-analytical solution to analyze the impact of pre-Darcy flow and SRV properties on the pressure behavior of the MFHW. Moreover, we used a local grid refinement method to verify the accuracy of the newly developed semi-analytical solution. The results show that the radial flow regime in the dimensionless pressure derivative will obviously disappear due to the pre-Darcy flow. Pre-Darcy flow in the SRV zone is adverse to the late production of the MFHW after the pseudolinear flow regime, while pre-Darcy flow in the unstimulated reservoir volume (USRV) zone is beneficial to increase the production during the regional interporosity flow regime. Meanwhile, the “groove” can be recognized from the pressure derivative curves, which mainly depend on the mobility ratio and the storage capacity ratio. In addition, due to the uneven distribution of fractures, the pressure derivative during the pseudoradial flow regime significantly deviates from 1/(2N).

Summary: Due to uneven proppant distribution and varied proppant sizes during hydraulic fracturing, artificial fractures of varying length, asymmetry, and varying conductivity are easily formed near the wellbore. The principal focus of this work is to investigate the pressure transient performance of a vertical well penetrated by multiple asymmetrical fractures with varying lengths and varying conductivities in a tight oil reservoir. A novel fracture flow equation was developed specifically to describe the flow behavior inside the complex artificial fractures mentioned above. By combining with the point source solution of the tight oil reservoir, a semianalytical solution was further obtained to analyze the pressure transient behavior of a vertical well with multiple varying-conductivity fractures in a tight oil reservoir. The accuracy and reliability of the newly-developed solution were verified by comparing with the result of a numerical model. With this new solution, fracture flux distribution for different conductivity modes, namely, linearly declining mode, exponentially declining mode, and elliptically declining mode, shows that the near-wellbore fracture flux of the exponential mode is greater than that of the other two modes, but the flux distribution near the fracture tips is on the contrary. Meanwhile, the transient flow characteristics under the above varying conductivity modes indicate that the exponentially varying conductivity has a significant influence on the early linear flow regimes, while the linear and elliptical mode only has a slight influence on the bilinear flow regime under high conductivity. Parameter sensitivity analysis reveals that the obvious inversion point occurring in the pressure derivative curves of uniform conductivity fractures disappears on the pressure derivative curves of varying conductivity fractures, and a weaker asymmetry, a greater adjacent fracture angle, and a larger fracture number and fracture length ratio are conducive to improve the fracturing stimulation effect. This study deepens our understanding of the transient flow performance of vertically fractured wells and helps to estimate artificial fracture properties and evaluate hydraulic fracturing performance.

Polymer flooding has been proved by many scholars for use in heavy oil reservoirs. However, due to mobility control effects and injectivity, selecting the appropriate solution viscosity is essential. It is difficult to form a deep understanding of the effect and mechanism of polymer flooding using conventional experimental methods with oil recovery as the reference standard, so it is necessary to conduct further study with the aid of simulation methods. In this study, a one-dimensional displacement mathematical model based on the Buckley–Leverett theory was established, and in the range of water–oil viscosity ratio from 0.1 to 0.6, the variation of water saturation along the flow caused by polymer solution was studied. The research results showed that under the action of a polymer solution, compared with water flooding, there was a decreasing region of water saturation along the flow due to oil phase accumulation. The larger the water–oil viscosity ratio, the larger the area of water saturation decline and the greater the degree of water saturation decline, resulting in a better the displacement effect. However, under the condition of oil–phase viscosity of 70 mPa·s, when the water–oil viscosity ratio reached 0.4, the range and degree of water saturation decline along the way no longer changed, all the crude oil that could be swept had been displaced, and the outlet end was close to producing only water, not oil; therefore, further increasing the water–oil viscosity ratio could not increase the oil recovery. At the same time, the increase in pressure had not changed, that is, the increase in pressure had not resulted in the same increase in oil recovery. When the viscosity of oil phase increased to 140 mPa·s, the same rule was displayed, the appropriate water–oil viscosity ratio was also 0.4. The paper analyzed the action mechanism of polymer solution through process description, and the results provided a clear selection method for selecting reasonable polymer solution concentration, as well as a reference for polymer solution range under different crude oil viscosity conditions.

Refracturing treatment is widely used to enhance the well productivity in shale gas reservoirs, particularly for initially fractured wells with low productivity. The principal of this work is based on the transient behavior of pressure and rate for a vertically refractured well in a shale gas reservoir, considering the fracture reorientation and adsorption and desorption property. Based on the point-source theory and Laplace transform, a semi-analytical solution for a refractured well is obtained by coupling the point-source solution of a shale gas reservoir and the solution of artificial fractures. The validation of this new solution is carried out smoothly by comparison with the results from the commercial software COMSOL. Five typical flow regimes are identified on the transient pressure curve, namely bi-linear flow regime, formation linear flow regime, mid-radial flow regime, inter-porosity flow regime, and pseudo-radial flow regime. A groove segment occurs on the transient-pressure derivative curve, and its width and depth largely depend on the adsorption and desorption constant and storativity ratio. Due to fracture reorientation, bi-linear flow regime, formation linear flow regime, and mid-radial flow regime may be significantly impacted. In addition, the transient rate of the refractured well in a shale gas reservoir is positively proportional to the storativity ratio, inter-porosity coefficient, and adsorption and desorption constant, while it is inversely proportional to fracture reorientation. These results provide important references for parameter design, property inversion, and productivity prediction of refracturing treatment in shale gas reservoirs.

Reorientation fractures may be formed in soft and shallow formations during fracturing stimulation and then affect well productivity. The principal focus of this study is on the productivity analysis for a horizontal well with multiple reorientation fractures in an anisotropic reservoir. Combining the nodal analysis technique and fracture-wing method, a semi-analytical model for a horizontal well with multiple finite-conductivity reorientation fractures was established to calculate its dimensionless productivity index and derivative for production evaluation. A classic case in the literature was selected to verify the accuracy of our semi-analytical solution and the verification indicates this new solution is reliable. Results show that for a fixed fracture configuration the dimensionless productivity index of the proposed model first goes up and then remains constant with the increase of fracture conductivity, and optimal fracture conductivity can be determined on derivative curves. Strong permeability anisotropy is a negative factor for well production and the productivity index gradually decreases with the increase of anisotropic factor. As principal fracture angle goes up, horizontal well’s productivity index increases correspondingly. However, the effect of reoriented fracture angle on the productivity index is not as strong as that of principal fracture angle. When reoriented fracture angle is smaller than principal fracture angle, reoriented factor should be as low as possible to achieve optimal productivity index. Meanwhile, well productivity index rises up with the increase of fracture number and fracture spacing, but the horizontal well has optimal reorientation fracture number and fracture spacing to get the economical productivity. Furthermore, the influence of the rotation of one central reorientation fracture on productivity index is weaker than that caused by the rotation of one external reorientation fracture. In addition, the asymmetrical distribution of one or more reorientation fractures slightly affects the productivity index when fracture conductivity is high enough.

In most oilfields, many wells produce in pseudo-steady-state period for a long time. Because of large reservoir pressure drop in this period, fractured reservoirs always show strong stress sensitivity and fracture closure is likely to occur near wellbores. The primary goal of this study is to evaluate productivity of vertical wells incorporating fracture closure and reservoir pressure drop. Firstly, a new composite model was developed to deal with stress sensitivity and fracture closure existed in fractured reservoirs. Secondly, considering reservoir saturation condition, new pseudo-steady productivity equations for vertical wells were derived by using the proposed composite system. Thirdly, related inflow performance characteristics and influence of some factors on them were also discussed in detail. Results show that fracture closure has a great effect on vertical well inflow performance and fracture closure radius is negatively correlated with well productivity. In this composite model, the effects of stress sensitivity of the inner and outer zone on well productivity are rather different. The inner zone’s stress sensitivity affects well productivity significantly, but the outer zone’s stress sensitivity just has a weak effect on the productivity. Strong stress sensitivity in the inner zone leads to low well productivity, and both inflow performance and productivity index curves bend closer to the bottom-hole pressure axis with stress sensitivity intensifying. Meanwhile, both maximum productivity and optimal bottom-hole pressure can be achieved from inflow performance curves. In addition, reservoir pressure is positively correlated with vertical well productivity. These new productivity equations and inflow performance curves can directly provide quantitative reference for optimizing production system in fractured reservoirs.

A fractured horizontal well is an effective technology to obtain hydrocarbons from tight reservoirs. In this study, a new semi-analytical model for a horizontal well intercepted by multiple finite-conductivity reorientation fractures was developed in an anisotropic rectangular tight reservoir. Firstly, to establish the flow equation of the reorientation fracture, all reorientation fractures were discretized by combining the nodal analysis technique and the fracture-wing method. Secondly, through coupling the reservoir solution and reorientation fracture solution, a semi-analytical solution for multiple reorientation fractures along a horizontal well was derived in the Laplace domain, and its accuracy was also verified. Thirdly, typical flow regimes were identified on the transient-pressure curves. Finally, dimensionless pressure and pressure derivative curves were obtained to analyze the effect of key parameters on the flow behavior, including fracture angle, permeability anisotropy, fracture conductivity, fracture spacing, fracture number, and fracture configuration. Results show that, for an anisotropic rectangular tight reservoir, horizontal wells should be deployed parallel to the direction of principal permeability and fracture reorientation should be controlled to extend along the direction of minimum permeability. Meanwhile, the optimal fracture number should be considered for economic production and the fracture spacing should be optimized to reduce the flow interferences between reorientation fractures.