Unlike complex structural plays in conventional clastic or carbonate reservoirs, shale formations have never been overly difficult to find or to map structurally. Therefore, in the early days of shale field development, seismic data were never the first tool of choice. Operators generally knew how deep, thick and laterally extensive these unconventional resources were since they are often the source rocks for more conventional reservoirs.
Since shale reservoir rocks were considered essentially homogeneous, horizontal drilling and hydraulic fracture completion strategies were the same everywhere. Perforation clusters were placed at regularly spaced intervals along the lateral. Shales were expected to fracture and produce hydrocarbons evenly from each completion stage.
Shale heterogeneity
In reality, production appeared almost haphazard. Shales were alarmingly heterogeneous. The first detailed maps of shale heterogeneity were drawn very slowly, at enormous cost, by the drillbit. In heavily drilled plays such as the Barnett—the first extensively developed unconventional shale in the world—colored maps of production (Figure 1, left) appeared as laterally complex and as discontinuous as highly faulted anticlinal structures offshore, yet without the structure. Evidence of heterogeneity showed up at multiple scales, from the field down to individual stages within a well. According to one study, 43% of the perforations in a certain play produced almost no hydrocarbons, while 30% produced more than 80% of total flow. Microseismic monitoring confirmed that some stages propagated hydraulic fractures far more extensively than others.
FIGURE 1. Left: The drillbit mapped 129.5 sq km (50 sq miles) of Barnett Shale heterogeneities (red=highest production; purple=lowest production). Right: The new seismic inversion algorithm mapped 114 sq km (44 sq miles) of Middle Bakken heterogeneities (red=highest azimuthal anisotropy; purple=lowest azimuthal anisotropy). (Source: Schlumberger)
The question, then, was how to predict—before drilling—where and in what manner a shale reservoir would hydraulically fracture. With such information, operators could drill and complete laterals only in the sweet spots.
To better characterize shale heterogeneities, which represent spatial variations in rock properties, more operators have been acquiring wide-azimuth (WAZ) seismic surveys in unconventional plays. Seismic data can provide initial information about porosity, total organic carbon, natural fracture density and fracture orientation as well as in situ stresses, which impact hydrocarbon storage, access and hydraulic fracture propagation. WAZ seismic can provide more information about how velocities and other key reservoir properties vary with azimuth. Nevertheless, inversion is necessary both to enhance resolution and to transform reflection data into quantitative rock properties.
The seismic inversion challenge
This is where many analyses go wrong. The inversion techniques widely used in the industry today are not appropriate for fractured shale reservoirs. They provide a good approximation of rock properties only when fractures are absent, but they cannot properly account for subsurface anisotropy, which is essential to accurately predict how to optimize hydraulic fracturing and understand fracture propagation in the presence of natural fracture networks.
In an isotropic medium such as a typical homogeneous sandstone, physical properties are essentially equal regardless of the direction in which they are measured. When certain properties vary with the direction of measurement, the medium is anisotropic. Shales are strongly layered systems consisting of anisotropic clay particles, micro-cracks and kerogen aligned parallel to the bedding. They create a type of anisotropy known as vertical transverse isotropy (VTI). Among other things, a seismic wave traveling parallel to bedding has a significantly different velocity to one traveling perpendicular to bedding. Thus, measurements of seismic and rock properties in VTI media depend on the angle between the direction of propagation and the bedding.
FIGURE 2. Top: Conventional seismic cannot distinguish the 18.3-m Middle Bakken shale from the upper and lower layers. Bottom: Orthotropic seismic inversion successfully resolves the target reservoir vertically and reveals heterogeneities laterally. (Source: Schlumberger)
Stressed and naturally fractured shales are even more complicated. These may have more complicated anisotropy that can be approximated as orthotropic media, in which azimuthal variations in the wave speed are superimposed on an otherwise strongly layered VTI medium by horizontal stress anisotropy and vertical fractures. The only proper way to invert WAZ seismic data in a fractured shale reservoir is to apply an orthotropic inversion algorithm. Until recently, this was simply impossible. The technology was not available. Operators typically applied conventional amplitude vs. offset or VTI inversion methods to WAZ seismic data. Without orthotropic inversion, however, one cannot determine the horizontal stress anisotropy. Well log data cannot provide this either.
The hydraulic fracturing process can be simulated using the Mangrove engineered simulation design in the Petrel platform. This shows that, in the presence of vertical fractures, hydraulic fractures tend to propagate more linearly when horizontal stress anisotropy is high, that is, when the difference in magnitude between the maximum and minimum horizontal stresses is large. Conversely, hydraulic fractures tend to spread out more widely among existing fracture networks—maximizing reservoir contact—when horizontal stress anisotropy is low. Without these details, it may be impossible for operators to optimize both the placement and orientation of wellbores and multistage perforation clusters for maximum well productivity.
Orthotropic inversion of WAZ data
To address this widespread challenge, Schlumberger recently developed the industry’s first high-resolution orthotropic inversion technique for WAZ seismic. It correctly estimates complex rock properties in strongly layered unconventional shales with natural fractures and azimuthal stress anisotropy. This unique amplitude vs. azimuth (AVAz) inversion workflow was first tested on synthetic data and has since been applied to real WAZ 3-D data in North America and the Middle East. Here, for example, is how the new inversion works in the Bakken, a naturally fractured unconventional play.
The Bakken shale consists of three distinct layers. The low-porosity, low-permeability middle Bakken, the primary producing zone, is less than 18.3 m (60 ft) thick, which is below seismic resolution. Operators cannot distinguish the middle Bakken from the upper and lower shales using conventional inversion of WAZ data. It has proven exceptionally difficult to reliably map lateral heterogeneities in rock properties, which are vital to locating the sweet spots.
Nevertheless, by applying the high-fidelity orthotropic inversion algorithm to the azimuthal seismic data, petrotechnical experts were able to fully resolve the middle Bakken (Figure 2) in terms of thickness and lithology as well as elastic and rock strength parameters. By building a suitable rock physics model, they also derived accurate fracture density and total porosity volumes as well as the maximum and minimum horizontal stress. As a result, it was possible to map the orientation and magnitude of azimuthal stress anisotropy in the middle Bakken producing interval (Figure 1, right). Interestingly, the heterogeneities captured in this map view mimic those highly complex production maps in early shale plays such as the Barnett (Figure 1, left) without having to drill hundreds or thousands of wells.
Promise for the future
Fractured unconventional shales are heterogeneous at multiple scales and anisotropic in multiple directions. Historically, operators mapped heterogeneities with the drillbit, an exceedingly expensive technique. Orthotropic inversion of WAZ seismic and stochastic rock physics modeling offers a promising alternative for the future.
First, operators can resolve thin layers with far greater resolution. This enables them to localize reservoir properties to the interval of interest rather than averaging across multiple zones. Second, they can accurately unravel each interval’s azimuthally dependent properties, including lithology, porosity, stress anisotropy and fracture density. With this information in hand, geoscientists and engineers can identify shale heterogeneities prior to drilling and place laterals and completions only in the best zones to maximize reservoir contact and optimize production. Oil and gas companies can drill fewer wells overall, minimize impact on precious water resources and the environment and, ultimately, maximize return on investment.
As shale resource development continues to expand worldwide, this breakthrough inversion technique will become even more critical to success.