Connectivity, Asphaltene Molecules, Asphaltene Gradients and CO2 Gradients in a Brazilian Carbonate Presalt Field
- Andre C. Bertolini (Schlumberger) | Jacyra Monteiro (Schlumberger) | Jesus Alberto Canas (Schlumberger) | Soraya S. Betancourt (Schlumberger) | Oliver C. Mullins (Schlumberger) | Santiago Colacelli (Schlumberger) | Ralf Polinski (Schlumberger)
- Document ID
- Society of Petrophysicists and Well-Log Analysts
- SPWLA 60th Annual Logging Symposium, 15-19 June, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. held jointly by the Society of Petrophysicists and Well Log Analysts (SPWLA) and the submitting authors
- 11 in the last 30 days
- 146 since 2007
- Show more detail
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.
|File Size||2 MB||Number of Pages||15|