What is Stimulated Reservoir Volume (SRV)?

Abstract

Ultra-low permeability shale reservoirs require a large fracture network to maximize well performance. Microseismic fracture mapping has shown that large fracture networks can be generated in many shale reservoirs. In conventional reservoirs and tight gas sands, single-plane fracture half-length and conductivity are the key drivers for stimulation performance. In shale reservoirs, where complex network structures in multiple planes are created, the concept of a single fracture half-length and conductivity are insufficient to describe stimulation performance. This is the reason for the concept of using stimulated reservoir volume as a correlation parameter for well performance. The size of the created fracture network can be approximated as the 3-D volume (Stimulated Reservoir Volume or SRV) of the microseismic event cloud. This paper briefly illustrates how the Stimulated Reservoir Volume (SRV) can be estimated from microseismic mapping data and is then related to total injected fluid volume and well performance. While the effectively producing network could be smaller by some proportion, it is assumed that created and effective network are directly related. However, SRV is not the only driver of well performance. Fracture spacing and conductivity within a given SRV are just as important and this paper illustrates how both SRV and fracture spacing for a given conductivity can affect production acceleration and ultimate recovery. The effect of fracture conductivity is discussed separately in a series of companion papers. Simulated production data is then compared with actual field results to demonstrate variability in well performance and how this concept can be used to improve completion design, and well spacing and placement strategies. Introduction Fisher et al. (2002), Maxwell et al. (2002), and Fischer et al. (2004) were the first papers to discuss the creation of large fracture networks in the Barnett shale and show initial relationships between treatment size, network size and shape, and production response. Microseismic fracture mapping results indicated that the fracture network size was related to the stimulation treatment volume. Figure 1 shows the relationship between treatment volume and fracture network size for five vertical Barnett wells, showing that large treatment sizes resulted in larger fracture networks. It was observed that as fracture network size and complexity increase, the volume of reservoir stimulated also increases. Fisher et al. (2004) detailed microseismic fracture mapping results for horizontal wells in the Barnett shale. This work illustrated that production is directly related to the reservoir volume stimulated during the fracture treatments. In vertical wells, larger treatments are the primary way to increase fracture network size and complexity. Horizontal well geometry provides other optimization opportunities. Longer laterals and more stimulation stages can also be used to increase fracture network size and stimulated reservoir volume. Mayerhofer et al. (2006) performed numerical reservoir simulations to understand the impact of fracture network properties such as SRV on well performance. The paper also showed that well performance can be related to very long effective fractures forming a network inside a very tight shale matrix of 100 nano-darcies or less.

Microseismic Imaging of Hydraulically Induced-Fractures in Gas Reservoirs: A Case Study in Barnett Shale Gas Reservoir, Texas, USA

“…[22]). Reference [23] estimated the stimulated reservoir volume (SRV) by the shape analysis of microseismic events cloud in three dimensions, but this imply equal events weightings and in consequence the estimated SRV represents the optimum value.…”

Production performance analysis of tight oil/gas reservoirs considering stimulated reservoir volume using elliptical flow

“…is always observed from microseismic-fracture-mapping results (Fisher et al, 2005;Maxwell et al, 2002;Mayerhofer et al, 2008). The SRV can create high conductivity flow channels around the wellbore which benefits the oil and gas production Clarkson, 2013).…”

A Novel “Soundless Cracking Agent Fracturing” for Shale Gas Reservoir Stimulation

“…The key factors affecting the morphology of post-fracturing network include horizontal in-situ stress difference, rock brittleness and natural fracture system (sedimentary bedding) [4]- [9]. In addition, the morphology of fracture network can also be affected by the fracturing operation parameters (volume of fracturing fluid, flow rate, spacing between fracturing segments [10], [11]) and fracturing techniques (horizontal well multistage fracturing, synchronous fracturing, zipper fracturing and refracturing [12]). …”

“…A large-size true triaxial fracturing simulation test using SCA was conducted. It was the first attempt of multi-stage fracturing and simultaneous fracturing for horizontal wells [12] that are unachievable in hydraulic fracturing physical simulation test [20]- [27] and it is also the first application of large high-energy IPT4106D linear accelerator non-destructive inspection system in carrying out high-energy CT scanning [25]- [28]. Meanwhile, the micro-fractures inside the post-frac rock cores were observed in order to explore the expansion rule of fractures in shale under the effect of stress conducting.…”