As all geoscientists know, the basement is the foundation upon which all other sedimentary layers rest—hence its name. Given its role as the foundation of the geologic column, basement understanding can often provide explorationists with critical insights into the relative productivity, prospectivity and economic potential of shallower horizons deposited above it, including in the reservoir zone(s) of interest.

Among other things, the basement, along with burial depth, acts as one of the primary heat sources that naturally matures kerogen-rich source rocks in subsurface hydrocarbon kitchens. Oil is the first hydrocarbon type to be liberated from kerogen as increasing levels of heat and pressure are applied in the kitchen; oil generation is followed by the subsequent liberation of wet-gas/condensate, dry gas and, when overcooked, CO2 and graphite. Knowing which hydrocarbon type one will be dealing with is an important factor in exploration decisions and in project economics, especially in shale plays.

The conventional wisdom that has prevailed in the petroleum industry is that thermal maturity varies in a straightforward linear manner with burial depth. The shale boom of the last decade has dramatically changed this conventional wisdom, as the most astute explorers now realize that variations in basement topography, fault networks and composition can all cause localized distortions in the burial depth vs. thermal maturity relationship.

For example, a senior technical adviser for one of the world’s largest pressure pumping companies stated at a Denver Rocky Mountain Association of Geologists luncheon several years ago that one of the key elements in identifying sweet spots in the Niobrara shale play of the Denver-Julesburg (D-J) Basin was “identifying the location of basement faults that have been reactivated and that, over the course of geologic time, have acted as conduits for hydrothermal fluids that affected the thermal maturity of the Niobrara.”

Houston-based NEOS GeoSolutions recently delivered the results from a 7,770-sq-km (3,000-sq-mile) multiphysics survey in the D-J Basin and, among other things, confirmed that this technical adviser was correct, as basement-related features, including intrusive complexes and fault-driven graben structures, underlie three of the D-J Basin’s more prolific fields: Wattenberg, Hereford and Pony. Interestingly, this same multiclient survey identified at least seven similar basement-related features that, at present, do not have significant exploitation or production operations underway.

FIGURE 1. This tilt derivative of magnetic reduced-to-pole data over roughly 2,500 sq km (1,000 sq miles) in the midcontinent U.S. is draped on a topographic map of the basement. Red and black lines show interpreted faults (determined by analyzing multiple datasets). Dashed white circles highlight horst block ‘pop-up’ features in the basement, which have proven to be highly correlative with the best producing wells in the area. (Source: NEOS GeoSolutions)

Basement analysis

In a different play several hundred miles away, a similar analysis of nonseismic datasets helped to map variations in the structure of the basement, including both topographic variations and fault regimes. An inversion of magnetic and gravity data constrained by several well control points and seismic lines helped to map subtle basement topographic changes throughout the area of investigation, while an analysis of various magnetic derivatives helped to identify basement faults, including “pop-up” features (horst blocks) that appear to have affected the location of sweet spots in the overlying reservoir intervals.

Figure 1 depicts the results of these analyses, with one of the magnetic datasets overlaid on a topographic map of the basement. The seven dashed white circles highlight the most productive intervals (which roughly measure 3.2 km or 2 miles wide by 6.4 km or 4 miles long). These high-production sweet spots are believed to be present because of subtle anticlinal draping over the basement horsts, whose bounding faults periodically reactivate, forcing the horsts upward. As these movements occurred over the course of geologic time, the overlying reservoir intervals were positively impacted both structurally (as more hydrocarbons were trapped in these structural highs) and through increased permeability and natural fracturing within the reservoir intervals overlying the horsts.

On another project in the Appalachian Basin, which involved sweet spot mapping in the Marcellus and Utica shales, NEOS undertook a multimeasurement geological and geophysical study over a four-county area of investigation in northwest Pennsylvania that spanned roughly 6,475 sq km (2,500 sq miles). The comprehensive interpretation involved integrating newly acquired airborne gravity, magnetic, electromagnetic (EM), radiometric and hyperspectral datasets with ground-acquired magnetotelluric and legacy seismic and well information.

It is commonly thought that the productivity of Appalachian reservoirs depends upon having abundant organic material, a suitable thermal regime (primarily related to burial depth of the shales) and localized natural fracturing. The project therefore initially focused on mapping variations in these properties. Well log and core data were analyzed to map total organic carbon variations. Gravity and magnetic data (calibrated by well and seismic information) were inverted to generate a series of 2-D structural cross sections and, ultimately, a regional 3-D model of the subsurface from which isopach and burial depth maps of the target shale horizons could be extracted. Lastly, magnetic, EM and seismic data were analyzed to identify zones of enhanced fault-induced natural fracturing.

FIGURE 2. Marcellus oil (green spots) and gas (red spots) production-proportionate circles are draped on a basement model. Basement composition and structure correspond to the Btu content of production. (Source: NEOS GeoSolutions)

Thermal profile

Adding to this list of factors, a chief geophysicist at one of NEOS’s clients speculated that changes in basement composition were altering the thermal profile across the area such that the normal “hotter with depth” linear relationship was no longer valid. He hypothesized that these changes in the region’s thermal profile were responsible for differences in production rates and especially the Btu content (i.e., liquids vs. gas) of the flowstreams obtained from newly drilled wells.

To test this theory, NEOS undertook an analysis of several multiphysics datasets, in particular, gravity, magnetic and EM, and applied workflows that included simultaneous joint inversions and Euler deconvolutions. The results, depicted in Figure 2, proved the hypothesis of this chief geophysicist: Compositional changes in the basement were in fact occurring and driving differences in the economic potential of the wells being drilled. The analysis suggested that a failed rift had developed across the area of investigation millions of years ago, introducing a new rock fabric with a different lithological makeup than the surrounding basement rock.

When the Marcellus Shale was subsequently deposited millions of years later, different portions of the source rock were subjected to different thermal regimes on an areal basis depending on where they were deposited, helping to determine whether wells subsequently drilled were more gas-rich or liquids-prone. As a consequence of this new insight, the project helped to better predict the flow rates and Btu content of newly drilled wells compared to more widely acknowledged geological and geophysical factors such as structural setting (e.g., burial depth or shale thickness) or acoustic attributes (e.g., brittleness, fracture density).

This isn’t to say that structural or acoustic insights aren’t valuable. But it does imply that a multiphysics approach, in which a variety of geophysical measurements are analyzed at depths of investigation ranging from the basement to the near surface, may provide a more constrained subsurface model and valuable set of related interpretive products than an approach that relies on only one or two geophysical measurements or properties.

These multiphysics projects are helping explorationists better understand the role that basement faulting might play in influencing sweet spot locations in unconventional shale reservoirs as well as the impact basement composition variations have on the relative liquids vs. gas content of the flowstreams from newly drilled wells.