Before diving into what reservoir fluid geodynamics (RFG) entails, we must first consider the comprehensive treatment of reservoir rock formations. Geological and geophysical professionals always consider the depositional setting and postdepositional alteration of geologic formations when trying to understand present-day reservoir structures.
Depositional settings include things like turbidite channel and sheet systems, injectites, nearshore facies, braided channels, carbonate platforms, and travertine versus stromatolite carbonates, to name a few. Postdeposition alterations include anticline formation, fractures, and faults—with fault block migration, deformation banding, cementation, and karst formation as important examples. Geologists call this postdeposition alteration of rock “geodynamics,” but I beg to differ. The term doesn’t encapsulate the process’s entire meaning, which is why I find “structural geology” to be a much better representation of what the postdeposition alteration of rocks entails. (That said, I still anticipate some pushback from geologists saying this term isn’t quite proper.)
Surprisingly enough, the same comprehensive workflow was never really employed for oil and gas. If the charging of oil and gas into reservoirs—generally treated by the well-developed discipline of petroleum systems analysis—represents the geological depositional setting of our previous example, then there’s no discipline to account for what happens during and after charge alteration and the redistribution of hydrocarbons over geologic time. That is, until now.
This is what RFG is: It’s a technical discipline within oil and gas analogous to “structural geology” in the assessment of rock formations. And because fluids respond to their container, the evaluation of comprehensive geodynamics (rock and fluids) is coherent. In other words, rock and fluids change hand in hand; any important change in the reservoir’s rock structure after hydrocarbon charge is typically reflected in fluid distributions inside the reservoir. This approach clarifies a reservoir’s properties by considering how rock and fluid evolved from deposition to the present day.
What is required to implement RFG?
RFG accounts for the evolution of reservoir fluids over geologic time, so it's essential to recognize whether the measured distribution of present-day reservoir fluids represents the equilibrated final state of the fluids or is still evolving. Given that this equilibrium is a matter of thermodynamics, establishing RFG required that we resolve the thermodynamics of asphaltene gradients in crude oils first. Therefore, we dedicated ourselves to determining the size of those asphaltenes to then apply Newton’s Second Law of Motion: F = mg, accounting for the force (F) of gravity (g) acting on a particle of mass (m).
Determining the size of asphaltenes was a difficult chemistry problem that took 25 years to resolve!
It turns out that there are three relevant asphaltene sizes: the molecule and two hierarchical nanocolloidal structures. This is known as the Yen-Mullins model, a highly vetted framework associated with two awards from the American Chemical Society. This model was then added to standard polymer solution theory to develop a novel approach to asphaltene gradients named the Flory-Huggins-Zuo equation of state (FHZ EOS). Given that Flory won the Nobel prize for polymer chemistry, the theory is considered solid. The question is whether such a simple theory can be applied to reservoir crude oils.
The answer lies in the data. Gauging the compositional equilibrium of reservoir fluids requires a thermodynamic analysis that is heavily reliant on gradients (particularly of asphaltene). The EOS has no lateral dependence, so the only gradient it predicts is vertical.
In analytical chemistry, there’s a primary bifurcation of measurement. The unknown sample (in our case, crude oil) is subjected either to
- separation science, such as gas chromatography (GC) and mass spectrometry (MS) or
- bulk phase spectral or radiative analysis, such as visible–near-infrared spectroscopy, X-ray spectroscopy, or high-Q ultrasonics.
Separation methods provide excellent compositional resolution but with uncertain overall concentrations, whereas spectral measurements are a bit the opposite: They’re excellent in variations but not in compositional resolution. That said, the latter is still very much preferred for accurate compositional gradient analysis, especially because spectral methods of downhole fluid analysis (DFA) remain complementary to the lab-based separation science of GC and GC-MS.
Why not use a cubic EOS for the thermodynamic analysis of RFG?
Reservoir crude oils consist of dissolved gas, liquids, and solids (the asphaltenes). But cubic EOS models—the first of which was developed in 1873 by Johannes Diderik van der Waals—are variations of the ideal gas law. This means they were designed to handle gas-liquid equilibria, not solids. They can describe the solution in which the asphaltenes reside (thus helping determine asphaltene phase behavior), but they cannot predict the state of the asphaltenes or their gravity term.
Gas-liquid evaluation is insufficient to launch RFG because
- There are too many parameters in a cubic EOS, thereby losing the governing physics (even though many parameters enable curve fitting).
- The error bars of the gas/oil ratio (GOR) measurements are too big—and GOR is one of the primary predictions of the cubic EOS.
- The GOR gradients are generally too small or even nonexistent.
In other words, it's rare that a GOR analysis can be used to determine the extent of reservoir fluid equilibrium. If a cubic EOS were sufficient to launch RFG, then somebody would have developed RFG soon after the cubic EOS was modified by Peng and Robinson in the 1970s, thereby resulting in its widespread application to crude oil.
The FHZ EOS, on the other hand, was designed specifically for treating the asphaltene gradients in a reservoir’s crude oil. And that makes all the difference.
Can’t geochemical evaluation achieve the same result?
No, geochemical analysis cannot evaluate the extent of equilibrium because it lacks thermodynamic evaluation of reservoir fluids. Nevertheless, many geochemical markers are formed by ratios of nearly equivalent chemicals, which should be invariant at equilibrium. For example, methane with a carbon-12 isotope and methane with a carbon-13 isotope behave almost identically in the reservoir. If equilibrium prevails, then there should be no variation of the ratio of carbon-12/carbon-13 in methane. If disequilibrium applies, there can be significant variations in this ratio due to methane’s different origins.
Where geochemistry is very useful is in garnering insights into the petroleum system context of reservoir fluids. For example, the thermal maturity of crude oil can be obtained by the ratio of two nearly equivalent hopanes:
- Ts is 18α(H)-22,29,30-trisnorneohopane (stable)
- Tm is 17α(H)-22,29,30-trisnorhopane (metastable).
At low temperatures of kerogen catagenesis, there is more Tm than Ts. At high catagenesis temperatures, Ts dominates. Should the reservoir fluid be low in maturity but lacking asphaltenes, those solids might be found elsewhere in the reservoir (e.g., a tar mat).
Geochemical markers provide insights for evaluating biodegradation, multiple charges, and multiple contributing kerogens, along with other processes such as the gas washing and water washing of crude oils. In fact, the complementary methods of geochemistry and RFG’s thermodynamics make for a powerful combination.
So, what does it mean to say the analysis of fluid and structural (geologic) geodynamics is coherent?
The coherent analysis of fluids and geology helps mitigate the risk factors of a reservoir. Changes in geologic structure are often evidenced in the fluid distribution during and after charge. Fluid equilibration requires massive fluid flow within the reservoir, something that only occurs with proper reservoir connectivity (at least during equilibration). In several case studies, reservoir fluids charged and equilibrated, then a fault block migrated. Fluid gradients that are reconstructed prior to fault throw exhibit this equilibrium and connectivity during charge.
“The excellent flushing of new lighter oil in and old heavy oil out shows excellent reservoir connectivity even in the complex structure of injectite reservoirs.”
Many reservoirs have parts with equilibrated fluids and other parts with disequilibrium fluids. In such cases, geologic features that interfere with fluid equilibrium (e.g., shale breaks or the deformation banding associated with halokinesis) can be identified.
Baffling (not a barrier) was observed in a reservoir that had interfering turbidites from multiple sources. The evolution of a reservoir as a fault relay ramp clarifies why aquifer support has been weak. The excellent flushing of new lighter oil in and old heavy oil out shows excellent reservoir connectivity even in the complex structure of injectite reservoirs.
What kind of reservoir challenges does RFG address?
A standardized workflow that incorporates RFG has been established. Nevertheless, each reservoir is unique, and its analysis requires a custom design to identify and address relevant concerns. (These are not what you might call “pattern recognition” or “big data” analyses.) But more than 80 unique RFG reservoir evaluations with 35 different operators show that many asset teams’ number one concern is reservoir connectivity, especially in exploration and early development.
Fluid compositional equilibration is a much tighter constraint on reservoir connectivity than pressure communication prior to production. Nevertheless, disequilibrium does not necessarily mean compartmentalized; processes such as diffusion can occur over geologic time in connected reservoirs.
For reservoirs in later development stages, other problems arise—problems such as bypassed oil, low recovery, and insufficient aquifer support. Again, the origins of these and other hurdles are specific to individual reservoirs. Reservoir studies have focused on a variety of challenges, including
- viscous oil and tar mats—especially those associated with aquifer support or production variations (routine issues that frequently occur in large Middle East fields long into production)
- large and disequilibrium GOR gradients
- wax issues
- flow assurance and comingling
- phase behavior of reservoir fluids
- location of the gas-oil contact.
Reservoir charge simulations (even simplified 2D simulations) have proved powerful in illuminating key attributes of concern and will probably continue to play a significant role in operators’ widespread adoption of RFG.
Speaking of which...
How is the oil and gas industry responding to the new discipline of RFG?
Oil and gas leaders across universities, operators, and professional communities have analyzed the foundations and published applications (about 30 reservoir evaluations) of RFG. Meanwhile, many notable professionals have been performing confidential RFG studies within their organizations. Not to mention the acceptance exhibited by numerous awards and distinctions citing RFG, including the Anthony F. Lucas Gold Medal (the highest technical award of the Society of Petroleum Engineers) and the inaugural ADIPEC Lifetime Achievement Award for Outstanding Technical Excellence to the Oil and Gas Industry.
In other words, the experts have weighed in, so the technical content of RFG is vetted. The challenge remains expanding its impact, and new developments generally take time. DFA took 10 years to go from operators saying, “Why would we want DFA when we can get all the analysis we need from a lab?” to “DFA is a must-have for sample quality and analysis.”
RFG is a more fundamental and esoteric concept than DFA. But if the evolution of reservoir rocks over geologic time is always properly evaluated, why not accord the same comprehensive approach to reservoir oil and gas?
