Downhole fluid analysis (DFA) accurately measures light absorption (optical density or OD) in different optical wavelength channels vertically and laterally in reservoirs providing accurate fluid gradients especially for dissolved gas, liquids and dissolved solids, the asphaltenes. DFA data can then be used for thermodynamic analysis using the cubic equation of state for gas-liquid equilibria, and the Flory-Huggins-Zuo equation of state (FHZ EoS) for solution-asphaltene equilibria. Thermodynamically equilibrated reservoir asphaltenes imply reservoir connectivity. Disequilibrium can imply recent or ongoing reservoir fluid geodynamic (RFG) processes, which impact major production concerns. Compositional analysis of the reservoir fluids using conventional gas chromatography (GC) and two-dimensional gas chromatography (GCxGC) can be used to validate the thermodynamic analyses, especially within a geochemical context. Several reservoirs are examined here with DFA, GC and GCxGC methods exploring many different reservoir concerns. Connectivity and its inverse compartmentalization are recurring concerns and are effectively addressed. GCxGC is shown to support simple thermodynamic modeling enabling connectivity analysis, which is then validated in production. Viscosity proflles throughout reservoirs are accounted for using simple modeling of asphaltene gradients. Biodegradation is shown to yield three endmember viscosity profiles, no in-reservoir gradients versus large in-reservoir gradients at the OWC or large gradients at the top of the oil column, and the governing RFG processes are clearly identified. Water washing is measured over a large range and has a secondary effect on oil quality; factors that control the extent of water washing are shown. A universal protocol is used for reservoir evaluation that elucidates key reservoir concerns efficiently. This protocol is generally applicable for reservoirs in all stages of exploration, appraisal and development.

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.

Abstract Asphaltenes can be dispersed in crude oils in 3 different forms; molecules, nanoaggregates (of molecules) or clusters (of nanoaggregates); these forms are codified in the Yen-Mullins model and relate to the extent of solvency of the asphaltenes in the crude oil. Many reservoir studies are used here to show the systematic behavior of the specific asphaltene species in crude oil and the corresponding magnitude of the asphaltene (and viscosity) gradients. In addition, the specific asphaltene species is related to the chemical origin controlling asphaltene onset pressure (AOP) and tar formation and depends on 1) the quality of the live crude oil solvent for asphaltenes and 2) the concentration of asphaltenes. Elevated quantities of solution gas of a reservoir crude oil significantly reduce the solvency of asphaltenes in crude oil. For low concentrations and/or good solvency, asphaltenes are dispersed in crude oils as molecules with small gradients (unless there are large GOR gradients). For moderate concentrations and/or moderate solubility, asphaltenes are dispersed as nanoaggregates with intermediate (gravity) gradients of asphaltenes. With large concentrations and/or poor solvency, asphaltenes are dispersed as clusters with very large gradients in reservoirs. These crude oils can also exhibit higher asphaltene onset pressures and/or phase separated bitumen or tar in the reservoir depending on the origin of asphaltene cluster formation. Secondary gas charge into oil reservoirs can yield tar and/or a high AOP. The effect of biodegradation on these factors is also discussed. The systematics presented here are helpful in understanding a variety of reservoir concerns associated with asphaltenes.

Abstract Reservoir architecture and the size and reservoir quality of producing bodies remain a central concern particularly in deepwater. In this case study, high-quality seismic imaging delineated the sand bodies and an intervening shale break between two stacked sands. Wireline evaluation in each well consisted of advanced DFA (Downhole Fluid Analysis), formation sampling and pressure measurements, borehole imaging and petrophysics. Reservoir fluid geodynamic analysis of Wireline asphaltene gradient measurements indicate that each sand body is laterally connected and that the shale break could be a baffle. Geodynamic analysis of reservoir architecture employing seismic analysis and wellbore imaging and petrophysical logging concludes the same. All other PVT and geochemical data are compatible with this assessment; nevertheless, the DFA-measured asphaltene gradients are shown to be superior to all other fluid measurements to determine reservoir architecture. The concurrence of high-resolution seismic imaging with advanced wireline for both formation and reservoir fluid geodynamics enables building robust geologic models populated with the accurate fluid structures of the reservoir. History matching months of production match most probable reservoir realizations which are now the basis of reservoir simulation. Future exploration with step-out wells are being optimized with this powerful workflow.

Abstract Reservoir fluid geodynamics (RFG) has recently been launched as a formal technical arena that accounts for fluid redistributions and tar formation in reservoirs largely after trap filling. Elements of RFG, such as analysis of biodegradation, have long been in place; nevertheless, RFG is now strongly enabled by recent developments: 1) downhole fluid analysis (DFA) allows routine elucidation of reservoir fluid gradients, 2) the development of the first equation of state for asphaltene gradients allows identification of equilibrium vs. geodynamic processes of reservoir fluids and 3) RFG analyses of 35 oilfields systematize a multitude of RFG processes and show their direct impact on wide-ranging production concerns. Thermodynamic analyses identifying reservoir fluid geodynamic processes rely heavily on measurement of fluid gradients to avoid ambiguous interpretations. The unique role of asphaltene gradients and their integration with other data streams are the focus herein. RFG oilfield studies have repeatedly shown that analyses of asphaltene gradients are critical to proper evaluation of RFG processes. Naturally, any reservoir concern that directly involves asphaltenes such as heavy oil, viscosity gradients, asphaltene onset pressure, bitumen deposition, tar mat formation, and indirectly, GOR gradients are strongly dependent on asphaltene gradients. Moreover, as shown in numerous case studies herein, asphaltene gradients can be measured with accuracy and the corresponding thermodynamic analyses allow explicit identification of RFG processes not traditionally associated with asphaltenes, such as analysis of connectivity, fault block migration, baffling, spill-fill mechanisms and many others discussed below. In turn, these processes imply other corroborative reservoir and fluid properties that can then be confirmed. Crude oil chemical compositional data, such as ultrahigh resolution two-dimensional gas chromatography, combined with geochemical interpretation, is highly desirable for understanding RFG processes. Nevertheless, biomarkers and other fluid properties often exhibit small gradients relative to standard deviations (except with biodegradation) but often can still corroborate specific RFG processes. In general, integration of fluid gradient analysis with other data streams including petrophysics, core analysis, stratigraphy, geology and geophysics is critical; nevertheless, which integration is most needed depends on particular reservoir attributes and RFG processes that are in question. Examples of data integration are shown for ten reservoirs undergoing various fluid geodynamic processes. Asphaltene gradient analysis is relatively new, yet it is essential for characterization of RFG processes.

Drilling up-dip wells, in close proximity to salt bodies is common practice in exploration for oil and gas. Imaging of sand layers close to salt however is difficult in many cases owing to the complex geometrical shape of the salt body as well as the rapid change in material properties between the sedimentary section and the salt body. In many cases this results in either drilling into the salt body by mistake, or too low in the target formations. This difficulty is very well known in the Gulf of Mexico shelf which has been a prolific oil and gas producing region for more than 70 years. Over the years, seismic data used for interpretation and prospect generation in this area has been sub-optimal in many cases. Many of the producing fields in the Gulf of Mexico shelf consist of steeply dipping hydrocarbon-bearing sands truncated against salt domes. Unfortunately, in many cases the salt bodies defining the reservoir edges are not well imaged on associated seismic data, making the accurate mapping of the producing reservoir very difficult (Foley et. al., 1991). One solution to the seismic imaging problem can be achieved by design and acquisition of new seismic data. In the past few years, more effort has taken place to acquire new data on the Gulf of Mexico shelf, but dense spacing of surface platforms makes acquiring new surface streamer data difficult. The newer data is mainly acquired using ocean bottom node technology which results in wide azimuth seismic data. The new data has the potential to have much better seismic resolution than the older narrow azimuth streamer data used by the industry for many years. In addition, nodes can be placed much closer to surface installations creating better illumination in these areas. However, because of the complexity of the geology in close proximity to salt bodies, the clear imaging of sedimentary layers near salt remains challenging even when the newest seismic data is used.

Abstract The reservoir modeling and simulation of Energy XXI's Gulf of Mexico Main Pass 61 Pod B Oil Field integrated seismic elastic properties and discontinuity analysis to improve reservoir definition, lithology distribution and to identify compartments and fluid flow pathways. The results provided key basis for improving the estimation of recoverable oil, field management decisions involving water injection and work-over completions, and the identification of un-swept potential for new drilling opportunities. Conventional reservoir modeling and simulation field studies often underutilize information contained in the seismic data. Wells sample the earth with high vertical resolution at a single location, but seismic provides highly sampled information in the intra-well space. Utilization of the intra-well seismic information leads to better definition of the reservoir and simulation results. The reservoir model integrated estimates of litho-fluid properties derived from prestack seismic inversion employing Bayesian classification methods. Reservoir boundaries and facies distributions were identified from shale and sand classification probabilities. Porosity distribution in the reservoir utilized acoustic impedance as a proxy. Seismic discontinuity analyses also provided a means to identify compartment boundaries, baffles, and lithologic barriers to fluid flow. Together, the integration of these seismic properties improved the accuracy of the geologic model and provided better understanding of reservoir production mechanisms.