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In toluene, asphaltenes are dispersed as molecules at low concentrations, as nanoaggregates at moderate concentrations, and as clusters of nanoaggregates at high concentrations. These three asphaltene species are codified in the Yen− Mullins model. For reservoir crude oils, equilibrated asphaltene gradients can be modeled with the Flory−Huggins−Zuo equation of state (EoS). The gravity term and other terms depend on the particle sizes of the asphaltenes which are given in the Yen−Mullins model; these different asphaltene species (molecular and two nanocolloidal species) have been identified in gravity gradients in various reservoir studies. Here, the asphaltene gradient in a large reservoir is examined and found to be consistent with a molecular dispersion of asphaltenes in the crude oil. A variety of fluid and reservoir properties are evaluated to ensure validity of the analysis, particularly of thermodynamic equilibrium of the reservoir fluid. For crude oil samples throughout the reservoir, downhole fluid analysis (DFA), gas chromatography (GC), and two-dimensional gas chromatography (GC×GC) with cubic EoS and geochemical interpretation are consistent with fluid equilibration. Pressure measurement and production results are also consistent with fluid equilibration. This analysis is applicable to other reservoirs; molecular dispersions of asphaltenes are expected for other light oil reservoirs.

Asphaltene gradient analysis in many wells in a large field match the Flory-Huggins-Zuo Equation of State (FHZ EoS) indicating equilibrated asphaltenes, thus reservoir connectivity. This analysis is consistent with data from over one year of production to date. Reservoir fluid samples were acquired with use of focused sampling techniques providing contamination free samples. Pressure measurements and many fluid properties are used to validate fluid equilibrium, including GOR and composition analyzed by the Cubic EoS, and a variety of markers in the condensate range, black oil range and the biomarker region. All analyses indicate equilibrium with the exception that the only two outliers in the asphaltene gradient curve are shown to be of different thermal maturity by utilizing the preferred biomarkers, the hopanes Ts and Tm. Moreover, the asphaltene abumdance in differently charged fluids varies by a factor of 6 while the maturity ratio Ts/(Ts+Tm) varies by 6% showing the sensitivity of asphaltene gradients for connectivity analysis. The modest levels of biodegradation (Peters- Moldovan rank=1) are used to constrain the petroleum system context of this reservoir considering that current reservoir temperatures significantly exceed biodegradation thresholds. There is evidence both that mildly biodegraded oil spilled into this reservoir and that some further biodegradation occurred in reservoir. Different gas-oil contacts in the field are associated with charge direction and show the limits of Cubic EoS for connectivity analysis in contrast to the good capability of the asphaltene gradients and FHZ EoS for this purpose. Moreover, the FHZ EoS analysis indicates that the asphaltenes are dispersed as a true molecular solution for this light oil in accord with the Yen-Mullins model of asphaltenes. Results from detailed whole-core and petrophysical analyses supports connectivity analysis. Core analysis shows the lack of any asphaltene deposition in the reservoir as expected from the fluid and asphaltene evaluations.

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Fluid geodynamics processes can alter the hydrocarbon accumulation in the reservoir and complicate the fluid distribution. The processes can be one or combination of late gas charging, biodegradation, water washing, spill-fill charging etc. Fault block migration is another geological process can take place after fluid charging, which results in the fluid re-distribution and brings extra challenges for reservoir evaluation. The understanding and evolution of the fluid geodynamics and fault block migration processes become the key to reveal reservoir connectivity, reservoir charging and geological structural evolution. This paper elaborates a case study from a Talos Energy's discovery in deep-water Gulf of Mexico, Tornado field from Pliocene formation, to illustrate the connectivity analysis cooperating fault block migration and fluid geodynamics. The high-quality seismic imaging delineated the sand bodies in the reservoir with a gross pay of 400 feet. The two wellbores in the main block A and one wellbore in adjacent block C all exhibit two primary stacked sands separated by an intervening shale break. The RFG (Reservoir Fluid Geodynamics) workflow was applied to this field for connectivity analysis, with integration of the advanced DFA (Downhole Fluid Analysis) data from wireline formation testing, advanced analytical and geochemical analysis of the oil, laboratory PVT and fluid inclusion testing data. The advanced DFA data includes fluid color (asphaltene), composition, Gas-Oil-Ratio (GOR), density, viscosity, and fluorescence yield to help assess connectivity in real-time and after laboratory analysis, which helped to optimize data acquisition and allow the early completion decisions. The DFA data was analyzed using the Flory-Huggins-Zuo Equation of State for asphaltene gradients and the Cubic Equation of State for GOR gradients. The resulting DFA-RFG analysis shows that in the main block A, the fluids in the upper and lower sands are separately equilibrated, in spite of the young age of the reservoir, indicating there is good lateral connectivity in each sand. The asphaltene content of the oil in the upper sand is slightly, yet significantly smaller, than that in the lower sand indicating that the intervening shale might be a laterally extensive baffle or possibly a barrier. Subtleties in the DFA data are more consistent with the shale being a baffle. Moreover, the biomarker analysis shows that all oils encountered are indistinguishable from a petroleum system perspective. This reinforces the DFA-RFG interpretation. However, seismic imaging shows that the intervening shale is not present at the half lower section of the reservoir. With guidance from RFG connectivity analysis, it is consistent with the geology understanding that the shale becomes thinner which beyond the seismic resolution. The paleo flow analysis based on high definition borehole images integrated with seismic interpretation confirmed that upper sand scoured away the intervening shale. The deposition modeling supports that the shale is a baffle. The sands from the well in the adjacent block C show a vertical shift of asphaltene distribution from block A. The extent of the 360feet vertical offset matches the fault throw from seismic imaging and from log correlation. The fluid properties including asphaltene content, API gravity, methane carbon isotope, GOR, density, are all consistent with the fault block migration scenario. A further complexity is that the upper fault block received a subsequent charge of primary biogenic gas after fault throw. This innovated approach provides guidelines for geophysical and geological interpretation regarding fault block migration and the hydrocarbon charging sequence. The field connectivity conclusions have been confirmed by over 1-year of production history to date.