J.G. Wang

Flow Consistency Between Non-Darcy Flow in Fracture Network and Nonlinear Diffusion in Matrix to Gas Production Rate in Fractured Shale Gas Reservoirs

Due to complex pore structures and ultra-low permeability in unconventional gas reservoirs, the flow consistency between the macro-flow in fracture network and the micro-flow or gas diffusion in matrix may significantly impact the production rate of fractured gas reservoirs. This study investigated the impact of this flow consistency on the production rate through the development of a numerical simulation model and its application to a shale gas reservoir. In this model, a fractured gas reservoir consists of fracture network and matrix. In the fracture network, gas flow was assumed to follow the non-Darcy law. In the matrix, a nonlinear diffusion model was proposed for the gas micro-flow through a non-empirical apparent permeability. This nonlinear diffusion model considered the advection and diffusion of the free-phase gas in nanoporous channels as well as the gas desorption in matrix. Further, the mass exchange rate between fracture network and matrix was calculated via a diffusion time which comprehensively considers both the diffusion capability and the size of matrix block. This numerical model was verified through history matching of the production data from two shale wells and then applied to a typical production well to investigate the effects of pore size in matrix, fracture spacing, and initial fracture permeability on production curve (i.e., production rate versus time). It is found that the production curve is significantly affected by this flow consistency. Pore size and initial fracture permeability play the key roles in this flow consistency. Fracture spacing and fracture permeability can alter the production curve. In this sense, the production curve can be designable through this flow consistency. Production efficiency can be improved through appropriate control of the fracturing degree of shale reservoir. Meanwhile, accurate measurement of shale pore size distribution provides an important parameter to the design of this flow consistency.

Impact of Water Film Evaporation on Gas Transport Property in Fractured Wet Coal Seams

Production data of coalbed methane have shown that coalbed may be wet for a long time after the completion of water flow and water–gas two-phase flow stages. In this period, water flows out in moisture vapor, but the water in matrix does not change so much. The moisture loss is mainly from the water film in fracture network. Experiments also observed that such a moisture loss has a profound impact on the storage and transport of coalbed methane. However, this impact has not been investigated so far. This study investigates this impact through following works: firstly, a new conceptual permeability model is proposed based on water film adhered to the surface of fractures in a dual-porosity porous medium. The effect of water film is further described in gas flow equation by a non-Darcy law with threshold pressure gradient. Thirdly, a coupled multi-physical model is established to consider the interactions among coal deformation, gas flow, gas sorption and moisture loss. This model is validated by the gas production data of a coal seam in the Fruitland formation of San Juan basin. Finally, four scenarios are computed to comprehensively study the impact of moisture loss. These simulations show that the proposed model can well fit the history of gas production data. Non-Darcy flow has different velocity profile from Darcy flow. For the non-Darcy flow, the gas flow velocity increases quickly, then slowly, and finally decreases once gas starts to flow at a point. Moisture evaporation with gas flow mainly occurs in the zone near wellbore. This loss has a delay to the gas flow velocity. It also reveals that this moisture loss in coal seams can significantly improve coal permeability and thus enhance gas production. Therefore, the change of water film has significant impacts on gas production.

A Two-Phase Flowback Model for Multiscale Diffusion and Flow in Fractured Shale Gas Reservoirs

A shale gas reservoir is usually hydraulically fractured to enhance its gas production. When the injection of water-based fracturing fluid is stopped, a two-phase flowback is observed at the wellbore of the shale gas reservoir. So far, how this water production affects the long-term gas recovery of this fractured shale gas reservoir has not been clear. In this paper, a two-phase flowback model is developed with multiscale diffusion mechanisms. First, a fractured gas reservoir is divided into three zones: naturally fractured zone or matrix (zone 1), stimulated reservoir volume (SRV) or fractured zone (zone 2), and hydraulic fractures (zone 3). Second, a dual-porosity model is applied to zones 1 and 2, and the macroscale two-phase flow flowback is formulated in the fracture network in zones 2 and 3. Third, the gas exchange between fractures (fracture network) and matrix in zones 1 and 2 is described by a diffusion process. The interactions between microscale gas diffusion in matrix and macroscale flow in fracture network are incorporated in zones 1 and 2. This model is validated by two sets of field data. Finally, parametric study is conducted to explore key parameters which affect the short-term and long-term gas productions. It is found that the two-phase flowback and the flow consistency between matrix and fracture network have significant influences on cumulative gas production. The multiscale diffusion mechanisms in different zones should be carefully considered in the flowback model.