Unconventional oil and gas reserves and production have significantly changed the energy game in North America – and for the most part this turnabout in domestic E&P has come from shale zones, which have been long recognized as source rocks for other reservoirs.
Now that many hydrocarbon-rich shales are the targets of the drill bit, geoscientists are working diligently to develop new approaches and technologies to better understand and produce them.
Horizontal drilling and multi-stage hydraulic fracturing have been key to economic development of these rocks.
These are the newsmakers that the public reads about.
There’s a raft of “behind the scenes” advanced technology applications that long precede the drilling stage. After all, these zones tend to be considerably more esoteric than the ordinary sandstone reservoir – or even the unconventional tight sandstone target.
Competent assessment of unconventional prospects demands integration of geology, geophysics, geomechanics, petrophysics and engineering, according to AAPG member Scott Singleton, ResSCAN technical manager GeoVentures group at ION Geophysical Corp.
He succinctly summarized what each of these disciplines brings to the table:
- Geology: Provides a regional stratigraphic and structural framework.
- Petrophysics: Supplies baseline rock property data from both logs and cores.
- Geophysics: Provides a means to extend the petrophysical rock property data away from the wellbore.
- Geomechanics: Describes the stress state both locally and regionally.
- Engineering: These data follow the other data usage and delineate the results of drilling, completion and production.
“All of these data types are essential to piecing together a complete reservoir assessment,” Singleton emphasized.
Looking at the Marcellus
He also noted that considerable attention has been directed to modifying the traditional conventional geophysical reservoir characterization workflow, to offer useful outputs to integrated asset teams in unconventional resource plays. These teams typically are comprised of both reservoir and drilling engineers.
“With this serving as the impetus, geophysicists are consolidating their efforts in four principal areas,” Singleton noted.
- Prediction of anisotropy from full azimuth data.
- Prediction of rock properties along the Vfast azimuth, or the true rock properties, which have minimal distortion owing to vertical fractures.
- Prediction of the three principal stresses.
- Fracture characterization.
Singleton said they have adopted this philosophy in their unconventional reservoir characterization workflow, where geophysics alone is insufficient to delineate true rock properties, the same as with conventional reservoir characterization.
Using the workflow they formulated, he and his colleagues conducted a study focused on a Devonian-age Marcellus shale prospect in Pennsylvania.
Singleton pointed out this effort was undertaken while he was at RSI.
The study results demonstrate that petrophysics, rock physics, geophysics and geology can successfully be integrated with reservoir and production engineering to characterize shale reservoirs.
Digging down, each data type yields information typically not provided by the others.
“The project objective was to determine production drivers at the wellbore using all available data and then to extrapolate this set of criteria away from the wellbore using only seismic data and its derivatives,” Singleton said.
“The results showed that rock brittleness and also pre-existing fractures can impact well production,” he noted. “Additionally, they showed that a comprehensive suite of fracture characterization methods, such as anisotropy and principal stresses, are necessary to effectively determine if a pre-existing fracture zone will reopen or stay closed when being subjected to hydraulic fracturing in this area.”
He asserted that a more robust method might be to incorporate reservoir quality data in the production prediction, e.g. gas-in-place, porosity and thickness.
Eagle Ford Comparisons
Over the course of the Marcellus study, Singleton had an “aha!” moment – involving an area far removed geographically from Pennsylvania.
“In addition to the Bakken, the production statistics available show that the Marcellus and the (Cretaceous-age) Eagle Ford in south Texas are the hottest shale basins in the United States,” he said. “Even a peripheral observation of these two basins indicates there’s a bunch of similarities.
“My immediate thought was, ‘hmm, I wonder if the analytical techniques I developed for the Marcellus are applicable to the Eagle Ford?’” Singleton said.
“I’ve seen others do exactly the same thing on the Eagle Ford that I did on the Marcellus,” he continued. “We’ve shared techniques, so I know we’re both going down the same path – I’ve seen their results, and they’ve seen mine.”
Singleton assembled a list of comparisons and contrasts between the Marcellus and the Eagle Ford (EF):
♦ Similarity: Depositional Environment
- Both units are underlain by a hard limestone that represents a regressive systems track, culminated by maximum regressive surface. These units are the Onondaga (Pennsylvania) and Buda (Texas).
- The base of each shale unit is a condensed section representing a transgressive systems track, culminating in a maximum flooding surface, which corresponds to the maximum organic content (MOC) due to restricted circulation and reducing conditions with low sediment input.
- Above the base of each shale unit is one or more regressive/transgressive system track pairs, eventually leading to lower sea levels and oxygenated conditions with mixed carbonate/clastic deposition (Tully – Pennsylvania, Austin Chalk – Texas).
♦ Difference: Lithology
- Marcellus – siliceous shale and silt, finely layered but mostly siliceous. EF – fine carbonate/shale interbeds, overall lithologic description of a marl. More and thicker organic shale beds in Lower EF, more and thicker limestone beds in Upper EF.
♦ Difference: Structure
- Marcellus – Structurally sits on the Appalachian forefront, and fracturing is prevalent and complex. Dominant J1 fracture system to the northeast (about 60 degrees), secondary J2 fracture system nearly orthogonal to J1. Less developed in the southern portion and likely sealed with calcite. More developed in the northeast and likely open, thus causing loss of containment during fracturing operations.
- EF – Structurally sits on the passive Gulf Coast margin. Dominant fractures are growth faults parallel to the coast from tectonic subsidence – thus, they’re often not well developed. Sealing is via calcite, similar to the host rock.
♦ Difference: Fracture Characterization
- Because of the differences in structural setting, horizontal velocity anisotropy can be high in the Marcellus (>15 percent) but is often low or can be nonexistent in the EF. This has implications on the use of full azimuth seismic surveys for reservoir characterization.
- Vertical velocity anisotropy is high in both formations due to fine layering of shales. This needs to be accounted for and removed from pre-stack seismic gathers prior to any analytical work.
- Post-stack fracture-sensitive seismic attributes (coherence, curvature, instantaneous dip, dip azimuth) still work well in both formations. Combined with neural networks, etc., fractured sediment ‘facies’ can be identified and mapped. These are then related to other geophysical, petrophysical and engineering features.
♦ Similarity: Reservoir Characterization
- Both units conform to the “Oreo cookie” model (hard limestone bounding soft, high-TOC shale), so the acoustic signature will conform to the same principles. Pre-stack simultaneous inversion will generate acoustic impedance, shear impedance and density volumes, from which reservoir properties can be calculated and calibrated with well control.
- Final outputs can be either rock properties (such as lithology or porosity) or engineering properties, including Young’s Modulus (measure of elasticity of a rock or other material), Poisson’s Ratio (measure of how a rock is going to deform in one area relative to another) and brittleness.