Simulation of the Production Performance of Fractured Horizontal Wells in Shale Gas Reservoirs Considering the Complex Fracture Shape

Abstract

Hydraulic fractures and natural fractures constitute the gas flow channels of fractured horizontal wells in shale gas reservoirs. Their shape and structural characteristics determine the production of horizontal wells and reservoir pressure propagation. To study the influence of hydraulic fractures and natural fractures on reservoir production performance at different degrees of complexity, a method was proposed to construct and simulate hydraulic fractures and natural fractures with complex shapes based on an embedded discrete fracture model, and the finite volume method was used to solve the model. On this basis, the effects of hydraulic fracture complexity and natural fracture connectivity on the production performance of fractured horizontal wells are analyzed. The results show that when the natural fracture orientation is perpendicular to the pressure wave propagation direction, the natural fracture will form a local shielding effect on the pressure propagation. Better natural fracture connectivity leads to better seepage capacity of the complex fracture network. Under the same conditions, hydraulic fracture complexity is more controllable than natural fracture connectivity, and the contribution of hydraulic fracture complexity to horizontal well production is underestimated. Increasing the complexity of hydraulic fracture is the key to improve the effect of hydraulic fracturing. Combining ant body technology and microseismic monitoring data, the method proposed in this paper is applied in the Longmaxi shale formation to obtain the history matching with the gas well production data and predict the estimated ultimate recovery.

Enhancement of Gas Production from Class 1-Type Hydrate Reservoirs with High-Pressure Rotating Water Jets in Horizontal Well Depressurization Production

“…Figure 1 depicts the schematic diagram of HPRWJ in marine sediments. After the horizontal well is drilled, the tool is lowered to the target location, and a high-pressure rotary water jet with sand or other mixtures is used to cut the sediment around the wellbore and form the disklike stimulation zone and the permeability can be up to 7.45 × 10 2 D. 13,15,17 According to previous studies, when the pumping pressure is 20 MPa, using the HPRWJ in the consolidated sediment can form a stimulation zone with a radius of 1 m and a width of 0.5 m, and the maximum pump pressure can reach 50 MPa. 18 The shear strength of sediment containing hydrates is about 0.5 MPa, which is much lower than the shear strength of consolidated sediment (greater than 5 MPa).…”

“…Meanwhile, referring to stimulation parameter settings in similar research studies. 13,15 In this work, the W (width) of the stimulation zones is set to a fixed 0.5 m, while the maximum R (radius), K (permeability), and P (porosity) of the stimulation zones are set to 5. The detailed stimulation zone settings for the above simulation cases are listed in Table 1.…”

“…The results showed that the RWJSG increased the cumulative gas production and the average gasto-water ratio of the hydrate by 116.3 and 46.1%, respectively, during the 720-day production period. 15 Previous research has substantially promoted the near-well stimulation technology in NGH production. However, previous work mainly focused on Class 3-type hydrate reservoirs, which are characterized by nonpermeable layers in both the upper and lower parts of the reservoir and a hydrate layer in the middle; the Class 1-type hydrate reservoir mainly consists of an upper hydrate layer and a lower free gas layer (FGL) (where gas and water can flow freely), and the performance of near-well stimulation technology in Class 1type hydrate reservoirs is still unclear.…”

Coalbed Methane Enhancement in Low-Permeability Reservoirs by Hydraulic Fracturing with Coated Ceramsite

“…Conventional hydraulic fracturing has been effective in promoting production in high-permeability coal reservoirs in the San Juan and Powder River Basins in the USA, the Alberta Basin in Canada, and the Bowen Basin in Australia . However, the permeability of coal reservoirs in China basically ranges from 0.1 to 1 mD, which is 1–3 orders of magnitude lower than those of the abovementioned areas. , It is difficult to inject quartz sand into such low-permeability, low-pressure, and loose coal reservoirs. Most of the quartz sand particles spread only in the small area near the shaft and cause sand plug easily. − Numerous field experiments have shown that conventional quartz sand fracturing is less effective in transforming low-permeability coal reservoirs in China, failing to promote the production or prolong the stable periods of production in CBM wells.…”

Three-Dimensional Numerical Simulation of Hydrocarbon Production and Reservoir Deformation of Oil Shale In Situ Conversion Processing Using a Downhole Burner

“…A range of studies and experiments are needed to understand the impact of various factors on oil shale in situ processing. Compared to the field tests and pilots, numerical simulation is a low-cost and helpful tool for designing and controlling operations and identifying and interpreting observations that differ from model predictions and has been used widely to explore the oil shale in situ conversion processing. ,− For instance, Fan et al investigated the effects of temperature and well layout on the oil shale in situ pyrolysis by numerically simulating the electrical heating process and showed that the oil production rate was highly dependent on electrical heating temperature. Youtsos et al built a one-dimensional model to analyze the thermal front development in porous reservoirs with reaction flows.…”