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Bertolini, Andre C. (Schlumberger) | Monteiro, Jacyra (Schlumberger) | Canas, Jesus Alberto (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Mullins, Oliver C. (Schlumberger) | Colacelli, Santiago (Schlumberger) | Polinski, Ralf (Schlumberger)
ABSTRACT The challenge of the limited number of wells in the development phase of a presalt field for obtaining data to evaluate reservoir connectivity before the field development plan (FDP) is ably addressed by deploying the latest wireline formation tester (WFT) technologies, including probes for efficient filtrate cleanup and fluid properties measurement. These measurements and methodology using a dissolved asphaltene EoS enabled developing insightful Reservoir Fluid Geodynamics (RFG) scenarios. Downhole Fluid Analysis (DFA) measurements of optical density (OD), fluorescence, inferred quantities of CO2 content, hydrocarbon composition and gas/oil ratio, of fluids sampled at discrete depth in six presalt wells are at the basis of this study. DFA data at varying depth captures fluid gradients for thermodynamic analysis of the reservoir fluids. OD linearly correlates with reservoir fluid asphaltene content. Gas-liquid equilibria are modeled with the Peng-Robinson equation of state (EoS) and solution-asphaltene equilibria with the Flory-Huggins-Zuo EoS based on the Yen-Mullins asphaltenes model. OD and other DFA measurements link the distribution of the gas, liquid and solid fraction of hydrocarbon in the reservoir with reservoir architecture, hydrocarbon charging history, and postcharge RFG processes. The objective of this study is to characterize fluid distributions in a presalt field by using well data including DFA from WFT, openhole logs, and a simplified structural/geological model of the field. From an understanding of the petroleum system context of the field, RFG scenarios are developed to link the observations in the existing datasets and suggest opportunities to optimize the FDP. An understanding of connectivity is developed based on asphaltene gradients. The asphaltene gradients exhibit a bimodal distribution corresponding to two the light oil model and black oil model of aspshaltenes. Asphaltene gradient modeling with DFA reduces uncertainty in reservoir connectivity. The CO2 content in some section of the field fluids limits the solubility of asphaltene in the oil, and over very large intervals, the small asphaltene fraction exists in a molecular dispersion state according to the Yen-Mullins model. This is the largest vertical interval yet published of such a gradient (300 meters gross pay) providing a stringent test of the corresponding model. This gradient of asphaltene molecules (light oil model) is compared with recent molecular imaging of asphaltene molecules showing excellent consistency. In addition, in limited intervals, larger asphaltene gradients are measured by DFA and shown to be consistent nanoaggregates (the black oil model). This bimodal behavior is compared with laboratory measurements of nanoaggregates of asphaltene molecules again showing consistency. This case study reinforces the applicability of the FHZ EoS in treatment of reservoir asphaltene gradients. The CO2 concentration was modeled with the modified Peng-Robinson EoS in good agreement with measurements in upper reservoir zones. Matching pressure regimes and asphaltene gradients in Wells B and C indicate lateral connectivity. The hydrocarbon column in this part of the reservoir in thermodynamic equilibrium. In Wells A, C, D, E and F the OD of the oil indicate an asphaltene content increase by a factor of four at the base of the reservoir as compared to the crest of the reservoir. This tripled the viscosity in Wells C and D as indicated by insitu viscosity measurements. The accumulation of asphaltenes at the bottom of the reservoir is most likely driven by a change in solubility due to magmatic CO2 diffusion into the oil column from the top down.
Mullins, Oliver C. (Schlumberger) | Primio, Rolando Di (Lundin) | Zuo, Julian Y. (Schlumberger) | Uchytil, Steve (Hess) | Mishra, Vinay K. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Achourov, Vladislav V. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Forsythe, Jerimiah (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Elshahawi, Hani (Shell)
Abstract Petroleum system modeling provides the timing, type and volume of fluids entering a reservoir, among other things. However, there has been little modeling of the fluid processes that take place within the reservoir in geologic time, yet these processes have a dramatic impact on production. Modeling and understanding of the reservoir then reinitiates with simulation of production for optimization purposes. The new discipline "reservoir fluid geodynamics" (RFG) establishes the link between the petroleum system context or modeling and present day reservoir realizations. This new discipline has been enabled by scientific developments of the new asphaltene equation of state and by the technology of downhole fluid analysis (DFA). Gas-liquid equilibria are treated with the traditional cubic EoS. Crude oil fluid- asphaltene equilibria are treated with the Flory-Huggins-Zuo equation of state with its reliance on the Yen-Mullins model of asphaltenes. Thermodynamic treatment is essential in order to identify the extent of equilibrium in oil columns, thereby identifying fluid dynamics in geologic time. DFA is shown to be very effective for establishing asphaltene gradients vertically and laterally in reservoir fluids with great accuracy. In turn, this data tightly constrains the thermodynamic analyses. These methods have been applied to a large number of reservoir case studies over a period of ten years. For example, case studies are shown that indicate baffling and lower production for parts of the reservoir that have slower rates of fluid equilibration. In addition, the newly revealed lateral sweep in trap filling is established via RFG case studies. Underlying systematics, especially for gas charge into oil reservoirs, have been revealed for a large number of fluid and tar distributions that enable a unifying and simplified treatment for seemingly intractable complexities. A case study is presented that shows three very different reservoir realizations in adjacent fault blocks for the same petroleum system model, where RFG explains all these differences. This enables key reservoir properties to be projected away from wellbore in ways not previously possible. Finally, universal work flows are shown which enable broad application of these methods through all phases of reservoir exploration and production.
Mullins, Oliver C. (Schlumberger) | Dumont, Hadrien (Schlumberger) | Forsythe, Julia C. (Schlumberger) | Chen, Li (Schlumberger) | Achourov, Vladislov (Schlumberger) | Meyer, John (Deep Gulf Energy) | Johansen, Yngve Bolstad (AkerBP) | Rinna, Joachim (AkerBP) | Winkelman, Ben (Talos) | Wilkinson, Tim W. (Talos) | di Primio, Rolando (Lundin) | Elshahawi, Hani (Shell) | Canas, Jesus (Schlumberger) | Betancourt, Soraya S. (Schlumberger) | Pomerantz, Andrew E. (Schlumberger) | Zuo, Julian Y. (Schlumberger)
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.
Gelvez, Camilo (The University of Texas at Austin) | Cedillo, Gerardo (BP America) | Soza, Eric (BP America) | Gonzalez, Doris (BP America) | Slotnick, Benjamin S. (BP America) | Moreno, Sol (BP America) | Pineda, Wilson (BP America) | Saidian, Milad (BP America) | Mullins, Oliver C. (Schlumberger) | Paul, Scott (Schlumberger) | Cañas, Jesus (Schlumberger) | Kulkarni, A lok (Schlumberger)
Abstract Reservoir Fluid Geodynamics (RFG) is a novel thermodynamic methodology that integrates pressure-volume-temperature (PVT), geochemical fingerprinting (GCFP) and reservoir geology with downhole fluid analysis (DFA) data to understand the evolution of reservoir fluids over geologic time. RFG enables the enhancement of reservoir description, estimation of reservoir fluid properties, and optimization of data acquisition plans. Deep-water reservoirs comprise multiple uncertainties in reservoir connectivity, viscous oil and flow assurance. This paper demonstrates the development of digital fluid sampling techniques for deep-water fields using the RFG workflow to predict fluid properties and distribution, to address compartmentalization uncertainties and flow assurance risks, as well as to redefine the well-logging program. Identifying key reservoir concerns is the first step during the implementation of the RFG workflow. Five questions define key reservoir concerns: Do optical density measurements explain the impact of biogenic methane on fluid behavior? Is it feasible to characterize baffling and fault compartmentalization? Can we predict reservoir fluid properties and assess flow assurance risks based on fluid behavior? Is it possible to identify all this in real time? How could we optimize future fluid sampling programs? The next step is to collect the available DFA data and to integrate it with the existing PVT and geochemistry datasets. This paper describes the evaluation of over 150 fluid sampling DFA measurements acquired during the operational history of a Gulf of Mexico field. Fluid behavior and optical density gradients are interpreted from a geological perspective to understand reservoir connectivity. A strong correlation between optical density and asphaltene content enables digital fluid sampling for different PVT and geochemical parameters. Lastly, a general correlation of optical density and asphaltene content is derived for multiple Gulf of Mexico oil fields. Optical density measurements support a consistent characterization of biogenic methane along the studied deep-water field, suggesting a relation to fluid migration and charging from deeper to shallower reservoirs. Likewise, optical density gradients and its integrated evaluation facilitate the identification of mass transport complex (MTC) baffles in the north part of the field and the characterization of fault compartments in the main reservoir sands. In addition, the RFG workflow reveals the difference in fluid behavior of sampled wells located in the area of a water injection project by identifying asphaltene clustering near the oil-water contact. The correlations of optical density and asphaltene content help to predict fluid properties and to estimate its uncertainty, benefiting risk assessment for asphaltenes deposits and flow assurance in deep water operations. Real time analysis of optical density measurements during fluid sampling permits the characterization of fluid properties and reservoir connectivity, optimizing future fluid sampling programs when fluid contamination reaches 10%. Ultimately, this innovative methodology conveys a general correlation to predict asphaltene content based on optical density measurements for deep-water reservoirs in the Gulf of Mexico, enabling the possibility to predict reservoir fluid properties in real time fluid sampling operations.
Achourov, Vladislav (Schlumberger) | Pfeiffer, Thomas (Schlumberger) | Kollien, Terje (Lundin) | Betancourt, Soraya S. (Schlumberger) | Zuo, Julian Y. (Schlumberger) | di Primio, Rolando (Lundin) | Mullins, Oliver C. (Schlumberger)
In this reservoir study, two adjacent fault blocks have been subject to the same initial liquid and subsequent gas charges, yet fluid characteristics are different. Wells in each fault block have a gas-oil contact (GOC) and an oil-water contact (OWC), thus all depth-dependent in-reservoir fluid geodynamic processes are visible within each well. The two adjacent fault blocks are found to be at different stages of the same reservoir fluid geodynamic process yielding a ‘movie’ with two time frames.
Diffusion of gas, from the late gas charge, into the oil column causes a significant increase of solution gas initially at/near the GOC. This increase in solution gas causes the asphaltenes to migrate down in the oil column. Well 1 is in the middle of this process exhibiting huge disequilibrium gradients of gas-oil ratio (GOR), saturation pressure and asphaltenes. In Well 2, the diffusion of gas reached the base of the column expelling most of the asphaltenes out of the oil column creating a 10-m tar mat at the base of the column. In Well 2, the oil is nearly in thermodynamic equilibrium in contrast to large disequilibrium in Well 1. Asphaltene extracts of core plugs are consistent with these fluid profiles and reinforce conclusions. The disequilibrium oil column is associated with low vertical permeability as seen with pressure interference testing indicating multiple baffles. In drillstem tests (DSTs), the equilibrated oil column exhibited 10x greater production than the disequilibrium oil column. Equilibrated asphaltenes are associated with good production; here, disequilibrium asphaltene gradients and poor vertical permeability are associated with low production due to reservoir baffling.