Poroelastic Pressure Transient Analysis: A New Method for Interpretation of Pressure Communication Between Wells During Hydraulic Fracturing

Abstract

In conventional reservoirs, pressure communication between wells is ascribed to hydraulic diffusion through the rock matrix. In this work we show that in unconventional (low-permeability) reservoirs, pressure communication due to matrix diffusion is insignificant, and pressure changes observed in an offset monitor well during stimulation of a nearby well are primarily due to poroelastic effects. We quantify the pressure transient response observed through external downhole gauges in monitor wells, when an adjacent well is fractured. Our goal is to model this poroelastic response and obtain important reservoir mechanical and flow properties, as well as hydraulic fracture geometry. A fully-coupled, 3-D, poroelastic, compositional, reservoir-fracturing simulator was used to simulate dynamic fracture propagation from a treatment well and compute the resulting pressure changes at one or more monitor wells. The pressure transient response is shown to depend on the reservoir fluid and formation properties (permeability, Biot's coefficient, stress anisotropy) and reservoir mechanical properties (Young's modulus). The impacts of hydraulic diffusivity versus poroelastic pressure response are compared. Type curves are presented that allow the pressure transient response to be interpreted for any general reservoir and well configuration. These type curves can be used to obtain reservoir mechanical and flow properties and the geometry of the propagating fracture. We show that modeling the fracture as a discrete discontinuity (as opposed to high permeability grid- blocks) is essential to obtain good agreement with field pressure observations. The pressure observed in the monitor well first decreases and then increases over time as the growing fracture interacts poroelastically with the monitor well. It is shown that this pressure transient signature is dominated by poroelastic effects for most unconventional reservoirs. The poroelastic response depends on the reservoir fluid type (gas, oil) and the mechanical properties of the reservoir. To simplify the quantitative interpretation of the pressure transient response we have developed type curves that allow us to determine the rock elastic and flow properties and the evolving geometry of the propagating fracture. If multiple monitor wells are utilized, the relative communication between different vertically separated reservoirs and the effects of the altered stresses in the reservoir induced by prior production / depletion can clearly be observed. We present, for the first time, general type curves for interpreting the pressure transient response of monitoring wells when an adjacent well is being fractured. Our representation of the propagating hydraulic fracture as an explicit discontinuity in a poroelastic medium is crucial to capture the poroelastic response observed. The impacts of reservoir heterogeneity (layering), fracture geometry, reservoir mechanical properties, hydraulic diffusivity and prior depletion on the pressure response are quantified. The interpretation of inter-well pressure interference data using the methods described in this paper presents a powerful new fracture diagnostic method.

Hydraulic fracture propagation in naturally fractured reservoirs: Complex fracture or fracture networks

“…Field observation also notice that planar fracture models with constant matrix permeability are capable of history matching production in most unconventional reservoirs, and rate transient analysis often reveals that productive surface area is much less than the "fracture networks" would imply. And the results from planar fracture propagation models match well with field data on inter-well pressure communication during hydraulic fracturing (Das et al, 2019;Seth et al, 2019). In addition, DFITs in most low permeability formations demonstrate extremely long after-closure linear flow behavior, which can only happen without the pressure interference of adjacent fractures.…”

A multiscale LBM–TPM–PFM approach for modeling of multiphase fluid flow in fractured porous media

“…On the other hand, the intrinsic permeability 𝐾 𝑆 11 showed a different trend, where the relatively small RVE with 𝜁 = 0.8, that is, 200 × 200 × 120 voxels 3 , had no interconnected pore channels and, hence, exhibited impermeable behavior. Afterward, the intrinsic permeability increased with the increase of the RVE size until 𝜁 = 1.2, that is, 200 × 300 × 180 voxels 3 , to almost reaching a value of 2.5 × 10 −8 mm 2 . Then, the permeability decreased with the increase of the RVE size to 𝜁 = 1.6, where the simulations with higher 𝜁 yielded almost stable…”

“…The appropriate size of the RVE was chosen by detecting the state where the aforementioned values reach a quasi-constant trend for the changing RVE size. As an initial choice, an RVE size of 200 × 250 × 150 voxels 3 , which is sample (𝑓) in Figure 2, has been considered for the computation of the intrinsic permeability and porosity of the intact material. Afterward, we started changing the size of the 𝐞 2 − 𝐞 3 plane of the aforementioned sample by multiplying the corresponding dimensions by a factor 𝜁 , whereby the dimension of 𝐞 1 direction has been kept constant at 200 voxels.…”

“…The topics of fluid flow through fractured porous media are present in various engineering applications, such as enhanced geothermal systems, 1,2 hydraulic fracturing in petroleum engineering, 3 and gas diffusion layers of polymer electrolyte membrane fuel cells. 4 In such applications, fluid flows through the cracks, in the intact porous ambient, as well as in the damaged interface between the fracture and the intact subdomains.…”

Analysis of Pressure Communication between the Austin Chalk and Eagle Ford Reservoirs during a Zipper Fracturing Operation

“…Often when fracture pressure communication is discussed, the observed pressure communication effects are attributed to changes in the in-situ stress of monitored well fractures, due to the propagation of hydraulic fractures in an offset well in the same reservoir, described further in [18]. Poroelastic interactions between monitor fractures and propagating hydraulic fractures, for a general unconventional reservoir and well configuration, are also modeled in cases where the wells are in the same, typically shale, formation [19]. These effects are not considered in our work since the Austin Chalk is a naturally fractured carbonate, which allows it to act as a conduit for actual physical fluid-based communication.…”