Use the rock physics bridge

Rock physics represents the link between geology and geophysics. Increasingly over the last decade, rock physics stands out as a key technology in petroleum geophysics, as it has become an integral part of quantitative interpretation of seismic and electromagnetic data. Ultimately, the application of rock physics tools can reduce exploration risk and improve reservoir forecasting in the petroleum industry.

Mind the gap

Traditionally, rock physics has focused on the understanding of how elastic properties and seismic signatures change as a function of hydrocarbon saturation, porosity, and pressure. With great breakthroughs in laboratory experiments and theoretical modelling, rock physics has extended its turf and today plays an important role in the basin scale characterization of the subsurface, being an integral part of well log, seismic, and electromagnetic data analysis.

The role of rock physics as a bridge between geology and geophysics poses new challenges and opportunities. The introduction of rock physics ‘templates’ (Ødegaard and Avseth 2004) as a tool for interpretation and communication has proven beneficial to the oil industry. The nifty thing with the templates is that rock physics models can be constrained by local knowledge from experienced geologists. Furthermore, the templates force the geological interpretation of well log and seismic data to be made within rigorous physical bounds. We can also use the rock physics templates to extrapolate away from a few observed wells in the earth and say something about expected rock properties and seismic signatures for various lithology and pore-fluid scenarios.

The sound of geology

Recent research studies have highlighted the importance and benefit of linking rock physics to geologic processes, including depositional and diagenetic trends (e.g. Dræge et al. 2006, Avseth et al. 2010). These studies have proven that lithology substitution can be as important as fluid substitution during seismic reservoir prediction. It is important during exploration and appraisal to extrapolate away from existing wells, taking into account how the depositional environment changes as well as burial depth trends. In this way rock physics can better constrain the geophysical inversion and classification problem in underexplored marginal fields, surrounding satellite areas, or in new frontiers.

It turns out that the rock texture we observe in cores and thin sections at the microscale strongly affects the seismic reflection amplitudes that we observe at the scale of tens of metres. We can apply rock physics templates to interpret sonic well-log measurements or seismic inversion data. In a way, we are using our effective rock physics models to downscale our geophysical observations to geological information about subsurface rock and fluid properties.

The memory of rocks

It is important to honour not only the present-day geology when we use rock physics templates for geological interpretation of well and seismic data. We should also know the burial history of the rocks. The rocks have ‘memory’ of the stress and temperature history since deposition, from mechanical and chemical compaction to episodes of perhaps uplift and burial. Therefore we occasionally observe well-cemented and high velocity rocks not corresponding with present-day temperatures and depths.

In other words, it is important to take into account the memory of rocks, as temperature and stress history make a significant imprint on reservoir and seal rocks. This is particularly important in areas with complex tectonics and uplift. With a better integration of basin analysis and geophysical interpretation, via rock physics models, we can more reliably interpret lithology and fluid parameters during hydrocarbon exploration and production.

Let’s rock it!

In a world in which energy insecurity is at the forefront of global challenges, building bridges across disciplines is a requirement for new discoveries and improved oil recovery. The field of rock physics has evolved to become one of these bridges, bringing geology and geophysics closer together. The time when large gaps separated our earth science disciplines is definitely over. So let’s rock the future together!

Q&A:

In clastics, seismic responses can be compared by substituting gas for brine or vice-versa. Is Gassmann’s fluid substitution valid for gas shales? If not what do you do?

Gassmann’s fluid substitution assumes isotropic medium and connected pores, where fluids have enough time to achieve pressure equilibration as the compressional wave passes through the rock. These assumptions are violated for shales, as the shale microstructure is anisotropic and the pores are not well connected. Inclusion based models like the DEM (Differential Effective Medium) or the SCA (Self-consistent approach) are more useful for fluid substitution in shales (Mavko et al., 2009). Anisotropic Gassmann or Brown and Korringa approach can also be applied to model fluid substitution in anisotropic rocks. However, these often suffer from our inability to measure enough parameters to completely characterize the stiffness tensor of shales. Mavko and Bandyopadhyay (2008) suggested an approximate form of fluid substitution, for vertically propagating waves in a transverse isotropic medium with vertical axis of symmetry (VTI), where one only need to know one of Thomsen’s parameters, the parameter δ.

How about generating model seismic responses for different TOC content in shales, or heavy oil in sandstones? Can you suggest how this could be done?

Assuming transverse isotropic layering, one could use Backus average to build an effective medium model and mix the different components, including kerogen, clay (normally illite) and silty quartz for organic rich shale. For tar sands with heavy oil, one could use granular medium theory and treat the heavy oil as a solid. Several authors have suggested workflows for solid substitution, to model and predict the seismic responses of sands with heavy oil (e.g., Ciz and Shapiro, 2007; Carcione et al., 2011; Saxena et al., 2012). Solid substitution can also be used to model varying total organic carbon (TOC) content in shales.

Talking about shales, could you explain how their anisotropy becomes more pronounced with the presence of kerogen, and how this effect could be accounted for in modeling the seismic response from such layers?

Looking at organic rich shales under the microscope, we see that the kerogen is often distributed in a patchy, yet transverse isotropic manner. Some studies have shown that kerogen may occur in connected networks, in which the clays are embedded. Lev Vernik did ground-breaking research on the effect of kerogen on elastic anisotropy by measuring ultrasonic velocities of hot-shale rock samples in different directions, and demonstrated how increasing kerogen content resulted in increasing anisotropy (Vernik, 1994). The most common way to model this is to use Backus average, as presented by Carcione et al., 2011, who also suggested a simple, heuristic approach of Krief et al. (1990) to account for anisotropy in organic rich shales. An alternative way was presented by Colin Sayers in Geophysics last year, who investigated the effect of kerogen on elastic anisotropy of organic-rich shales using effective field theory (Sayers, 2013).

The maturation of kerogen in shale formations creates natural fractures, which when combined with their intrinsic or layer anisotropy would essentially make the problem one of orthorhombic anisotropy. How can one account for this? Is it being done in the industry?

One could model orthorhombic anisotropy, for example, by combining VTI with HTI (e.g. Gelinsky and Shapiro, 1995); however, the number of unknown parameters used in the modeling will be large; we often have a very hard time determining the Thomsen parameters for a transverse isotropic medium. I haven’t seen practical examples where orthorhombic modeling has been done in the industry. Also, with maturation, there are other complex issues happening to the shales; the rocks get more consolidated, clay minerals transform, and diagenetic cement can counteract or enhance the anisotropy. The expulsion of gas and generation of overpressure can also drastically affect the seismic properties. With so many unknowns, it is a great challenge to model organic-rich shales during maturation, and there is really no single solution. Also, we need more data from different areas and at different maturation stages to fully understand the rock physics of organic rich shales. When it comes to rock physics modeling of the complex texture of shales, we should still keep in mind what a famous physicist once said: "Make your theory as simple as possible, but no simpler.” Crack-like porosity in a mature, organic-rich shale could be assumed isotropic using inclusion based models like DEM, in combination with Backus average to account for transverse anisotropy caused by the layering.

Rock physics has gone digital now so that one can characterize the pore volume, pore types and many other rock properties and organic matter. How much do you think this advancement helps us in our understanding of the rocks?

I believe that digital or computational rock physics has a great value when it comes to determining which modeling approach is more realistic. Some of the unknowns can be solved by digital rock physics, making it easier for us to constrain our models. Digital rock physics can also be used to create more data points to test and calibrate our models to. Digital rock physics also has the potential to change the “observed” texture to another “what if” scenario, for example by changing the maturity of a digital source rock, to determine the associated effect on elastic properties.

Despite its importance, how much integration of rock physics is being done in our geophysical analysis?

The way I see it, in the last decade rock physics has really moved from the table of the expert, to the practitioner’s desk. We have moved away from rock physics being solely a laboratory or a computational task, to a discipline that is integrated with other fields of geosciences. Many interpretation software companies have included easy-to-use rock physics toolboxes in their software. And rock physics is applied more and more in a field- and basin-scale manner, integrated with other disciplines, to better understand the seismic signatures between wells and away from wells, both during exploration and production.

Let me ask you an open ended question: what in your opinion are the major future challenges for rock physics analysis?

Rock physics is still considered something obscure and abstract for many in the oil industry. We need to continue spreading the message that rock physics is needed for quantitative interpretation, and quantitative interpretation is more and more important for the detection of subtle traps not easily found from conventional interpretation techniques. We need more integration with basin modeling, and rock physics still has a great potential to improve velocity models used for seismic migration and inversion. This also leads us to one of the key challenges in rock physics; the issue of scale. It always strikes me how the knowledge of microstructure at millimeter scale is crucial for the understanding of seismic signatures of reservoir rocks. At the same time, it often strikes me how ignorant we are of the larger scale changes when we do our modeling. For instance, the transition from soft sediment to hard rock often happens at burial depths where we are looking for oil and gas; if we neglect this transition, we can easily go wrong on our fluid predictions.

What would be your words of wisdom for young entrants to our profession?

Think outside of the box, dare to challenge the conventional wisdom. New discoveries will be made by geoscientists who are creative and innovative and come up with new ideas. Don’t only follow the existing “best practices”. Geophysics is a field that allows for creative thinking, and there are plenty of unsolved problems yet to be solved in our industry. And dare to cross borders between disciplines; the most interesting problems to work on are often hidden in the borderline area between existing disciplines.

References

Avseth, P, T Mukerji, G Mavko, and J Dvorkin (2010). Rock-physics diagnostics of depositional texture, diagenetic alterations, and reservoir heterogeneity in high-porosity siliciclastic sediments and rocks – A review of selected models and suggested work flows. Geophysics 75, 7531–47.

Dræge, A, T A Johansen, I Brevik, and C Thorsen Dræge (2006). A strategy for modeling the diagenetic evolution of seismic properties in sandstones. Petroleum Geoscience 12 (4), 309–323.

Ødegaard, E, and P Avseth (2004). Well log and seismic data analysis using rock physics templates. First Break 22, 37–43.