Marine Mudstone Attributes at Core, Well Log and Seismic Scales: Implications for Characterizing Fluid Flow in Thick Subsurface Shale Successions

The recent increase in high-fidelity subsurface data (core, logs and seismic) from unconventional plays has shown that mudstone succesions are much more heterogeneous with regard to flow properties than typically assumed. Much of the flow heterogeneity is ultimately controlled by stratigraphic variations and dictated by the extremes of the lithofacies, which are often volumetrically insignificant, and therefore easily overlooked in a sampling and rock characterization strategy. Recognition of the flow extremes in cores and outcrop, appropriate upscaling to wireline log and seismic attributes, will significantly improve our abilities to predict patterns of fluid flow and retention within overall shale successions. This paper will demonstrate the nature of this variability and how to sample and upscale it from rock properties through seismic attributes in a number of subsurface case studies.

Fine-grained, clay-mineral rich sedimentary rocks deposited in the marine realm are the most common sedimentary rock type preserved in the stratigraphic record. Traditionally, marine mudstones were interpreted to be deposited by gravitational settling through the water column. The implications were that depositional conditions at the seafloor were quiet and steady, resulting in the interpretation of rather homogeneous deposits with fairly uniform attributes.

Within the petroleum industry, the study of mudstones was historically limited to two main disciplines: source rock and seal evaluation. Seal evaluation focused on defining the interface between reservoirs and overlying mudstones (seals). Typically, mechanical and capillary attributes of a limited set of samples are related to the bulk properties of the sealing interval. Some attempts were made to relate sealing attributes to bulk sequence stratigraphic packages ( Dawson & Almon, 2002 ), but limited sample measurements were still related directly to the bulk properties of thick, laterally extensive intervals.

Source evaluation focused on placing specific geologic periods in the context of regional or global anoxic events. With the engrained notion that mudstones recorded steady and quiet depositional conditions, heterogeneity in mudstone attributes with regard to preservation of organic matter are most easily explained with bottom water anoxia. Research on outcrops and well logs by Exxon workers in the late eighties and early nineties ( Creaney & Passey., 1990 ; Bohacs, 1998 ) demonstrated degrees of variability that could be tied to predictive stratigraphic frameworks (and hence, varying depositional conditions as fundamental controls on source rock preservation), but this work did not lead to a significant relook at how mudstone sequences were evaluated for rock and flow properties.

This attitude changed significantly during the rise of shale petroleum plays (“unconventional plays”) in the early 2000s. Suddenly, petroleum geologists were asked for detailed reservoir descriptions and predictions for shale sequences, much as they were used to doing for carbonate and sandstone reservoir intervals. This lead to a realization that (a) flow attributes of mudstone successions varied greatly at all scales, and (b) the industry was poorly equipped to provide meaningful characterizations and predictions for this variability. The necessity for reservoir characterization of mudstone successions, combined with a wealth of high-fidelity subsurface data (core, logs and seismic) coming available, has led to a significant improvement in our ability to characterize mudstone successions ( Passey et al., 2010 ), appreciation of the link between depositional processes and diagenesis ( Macquaker et al., 2014 ) and use modern oceanographic datasets to better understand the controls on transport and deposition of mudstones.

A number of the learnings from the unconventional revolution should be integrated back into evaluations of mudstone successions for applications related to the mechanical and capillary attributes important for understanding subsurface flow and retention of fluids. A key learning is the appreciation for very significant stratigraphic heterogeneity exerting a first-order control on subsurface fluid flow. Any characterization of subsurface shale successions has to include a robust sampling characterization within the stratigraphic framework. In addition, relating a sample measurement to critical and bulk properties of larger units (“upscaling”) has to be done within the understanding of the stratigraphic framework. Here, we will demonstrate examples of this process with a number of subsurface case studies.

Figure 1 shows an example of a detailed stratigraphic model of the Cretaceous Mowry Shale Formation (a mudstone succession containing source rocks, seals and hydrocarbon accumulations) populated with capillary properties to simulate the flow and retention of immiscible fluids (oil and gas) within a water-wet medium. The model was constructed using targeted sampling of identified lithofacies from outcrop and core, and using stratigraphic models to populate the succession with the appropriate lithofacies using upscaling of the attributes to wireline log properties. A key observation from this work shows the fundamental control of ash beds in controlling the flow and retention of hydrocarbon fluids within the succession. While volumetrically insignificant (and easily overlooked in a sampling strategy), these intervals with high capillary threshold pressures dominate the overall migration and retention patterns of hydrocarbon fluids within the succession.

While unconventional with regard to the required drilling and stimulation technology, study of numerous “shale gas” plays demonstrated that hydrocarbon liquids had migrated into certain mudstone reservoir facies and been retained through capillary mechanisms in subtle stratigraphic traps. Subsequent burial of these oil reservoirs led to secondary cracking of oil in conventional pore spaces and the development of solid pyrobitumen filled with gas. An important consequence of these observations is that certain mudstone facies possess pore geometries that allow for trapping of oil at relatively high oil saturations and relatively low capillary pressures. As such, while traditionally viewed as source rocks, seals and “unconventional” reservoirs, many of these mudstone successions contain attributes akin to conventional reservoirs with regard to the potential to retain significant amounts of hydrocarbon fluids through displacement of water in conventional pore systems.

In certain cases, unstimulated flow tests suggest significant permeability networks existing within mudstone successions, even in the absence of obvious fracture networks or sandier interbeds. In order to match reservoir simulations, facies have to be populated with relatively high horizontal permeabilities ( Fig. 2 ). Microscopic studies reveal the presence of mm-scale horizontal bitumen-filled seams, which may have originated as mechanical flow networks during hydrocarbon migration, and continue to provide subtle, yet effective pathways for efficient migration of fluids through mudstone successions.

In summary, mudstone successions are much more heterogeneous with regard to flow properties than typically assumed. Much of the flow heterogeneity is ultimately controlled by stratigraphic variations and dictated by the extremes of the lithofacies, which are often volumetrically insignificant, and therefore easily overlooked in a sampling and rock characterization strategy. Recognition of the flow extremes in cores and outcrop, appropriate upscaling to wireline log and seismic attributes, will significantly improve our abilities to predict patterns of fluid flow and retention within overall shale successions.