Hadrien Dumont

Mapping and Modeling Large Viscosity and Asphaltene Variations in a Reservoir Undergoing Active Biodegradation

Viscosity is one of the key reservoir fluid properties. It plays a central role in well productivity and displacement efficiency and has a significant impact on completion strategies. Accurately assessing areal and vertical variations of viscosity will lead to more realistic reservoir simulation and optimal field development planning. Downhole fluid analysis (DFA) has successfully been used to measure the properties of reservoir fluids downhole in real time. DFA has excellent accuracy in measuring fluid gradients which in turn enable accurate thermodynamic modeling. Integration of DFA measurements with the thermodynamic modeling has increasingly been employed for evaluating important reservoir properties such as connectivity, fluid compositional and property gradients. The thermodynamic model is the only one that has been shown to treat gradients of heavy ends in all types of crude oils and at equilibrium and disequilibrium conditions. In addition, fluid viscosity depends on concentration of heavy ends that are associated with optical density measured by DFA. Therefore, mapping viscosity and optical density (heavy end content) is a new important application of DFA technology for use as assessment of reservoir architectures and a mutual consistency check of DFA measurements. In this case study, a very large monotonic variation of heavy end content and viscosity is measured. Several different stacked sands exhibit the same profiles. The crude oil at the top of the column exhibits an equilibrium distribution of heavy ends, SARA and viscosity, while the oil at the base of the oil column exhibits a gradient that is far larger than expected for equilibrium. The fluid properties including SARA contents, viscosity and optical density vary sharply with depth towards the base of the column. The origin of this variation is shown to be due to biodegradation. GC-chromatographs of the crude oils towards the top of the column appear to be rather unaltered, while the crude oils at the base of the column are missing all n-alkanes. A new model is developed that accounts for these observations that assumes biodegradation at the oil-water contact (OWC) coupled with diffusion of alkanes to the OWC. Diffusion is a slow process in a geologic time sense accounting for the lack of impact of biodegradation at the top of the column. An overall understanding of charging timing into this reservoir and expected rates of biodegradation are consistent with this model. The overall objective or providing a 1st-principles viscosity map in these stacked sand reservoirs is achieved by this modeling. Linking DFA with thermodynamic modeling along with precepts from petroleum systems modeling provides a compelling understanding of the reservoir.

Variation of Asphaltene Onset Pressure Due to Reservoir Fluid Disequilibrium

Reservoir fluids in a single compartment can be in a state of gross thermodynamic disequilibrium. The equilibration of reservoir fluids is a slow process in part mediated via diffusion, an inherently very slow process. When reservoir fluids are subjected to other, faster processes, equilibration can be precluded. A common event in reservoirs especially in deepwater is a late gas charge into an oil-filled reservoir. In this case, the gas can quickly migrate to the top of the reservoir through fault planes without mixing with the existing reservoir fluid. This newly charge gas can then diffuse down into the oil column thereby creating very large gradients of many fluid properties such as gas-oil ratio (GOR) and bubble point pressures. In addition, asphaltene solubility is highly sensitive to GOR (as shown in the Flory-Huggins-Zuo Equation of State (FHZ EoS)), thus very large gradients of asphaltene content can likewise be established. Where solution gas is high, asphaltene instability is expected and Flow Assurance problems can occur. Gravity segregation of asphaltenes due to redistribution of the colloidal speciation of the asphaltenes in accordance with the Yen-Mullins Model can occur and results in asphaltene gravity currents. This process can result in significant variations in asphaltene concentration throughout the column. This convective process can yield large asphaltene concentrations at the base of the column thereby producing corresponding Flow Assurance concerns at the base. The combination of all these processes associated with gas charge into black oil can create a large gradient in asphaltene onset pressure (AOP). Such cases if not properly analyzed can give rise to mismanagement of Flow Assurance concerns. In this paper, we discuss case studies that exhibit such potentially problematic fluid columns. Simulated cases are also modeled to provide guidance for optimal management of AOP variations. The relationships of these Flow Assurance problems with other production problems are clarified. The ability to model asphaltene gradients with the FHZ EoS is seen to help significantly in understanding of asphaltene phase behavior of reservoir fluids.

DFA Connectivity Advisor: A New Workflow to Use Measured and Modeled Fluid Gradients for Analysis of Reservoir Connectivity

In deepwater and other high-cost environments, reservoir compartmentalization has proven to be a vexing, persistent problem that mandates new approaches for reservoir analysis. In particular, methods involving reservoir fluids can often identify compartments; however, it is far more desirable to identify reservoir connectivity. Downhole fluid analysis (DFA) has enabled cost-effective measurement of compositional gradients of reservoir fluids both vertically and laterally. Modeling of dissolved gas-liquid gradients is readily accomplished using a cubic equation of state (EOS). Modeling of dissolved solid (asphaltenes)liquid gradients can be achieved using the newly developed Flory-Huggins-Zuo equation of state (FHZ EOS) with its reliance on the nanocolloidal description of asphaltenes within the Yen-Mullins model. The combination of new technology (DFA) and new science (FHZ EOS) provides a powerful means to address reservoir connectivity. It has previously been established that the process of equilibration of reservoir fluids generally requires good reservoir connectivity. Consequently, measured and modeled fluid equilibration is an excellent indicator of reservoir connectivity. However, some reservoir fluid processes are faster than equilibration rates of reservoir fluids. The often slow rate of fluid equilibration makes it a suitable indicator of connectivity. Consequently, measurement of disequilibrium can still be consistent with reservoir connectivity. Moreover, the two fluid gradients, dissolved gas-liquid versus dissolved solid-liquid can be separately responsive to different fluid processes, thereby complicating understanding. A workflow is developed, the DFA reservoir connectivity advisor, to enable interpretation of the implications of measured fluid gradients specifically with regard to reservoir connectivity. Reservoir connectivity is difficult to establish in any event; analyses of fluid gradients can be placed in a context of the probability of connectivity, thereby significantly improving risk management.

Flow Modeling and Comparative Analysis for a New Generation of Wireline Formation Tester Modules

Wireline formation testing (WFT) is an integral part of reservoir evaluation strategy in both exploration and production settings worldwide. Application examples include fluid gradient determination, downhole sampling, fluid scanning in transition zones, as well as interval pressure transient tests (IPTTs). Until recently, however, formation testing was still challenging and prone to failure when testing in low-mobility, unconsolidated, or heavy-oil-bearing formations, especially with single-probe type tools. A new-generation WFT module with a 3D radial probe expands the operating envelope. By using multiple fluid drains spaced circumferentially around the tool, the new module can sample in tighter formations and sustain higher pressure differentials while providing mechanical support to the borehole wall. We performed a detailed flow modeling-based analysis of the contamination cleanup behavior during fluid sampling with the new module. Using both miscible (sampling oil in oil-based mud) and immiscible (sampling oil in water-based mud) contamination models we studied the cleanup behavior over a wide range of formation properties and operating conditions. Comparison of the cleanup performance of the new module with the performance of conventional single-probe tools demonstrates that the new module is 10 to 20 times faster than the single-probe tools when sampling in tight formations. Finally, we also compared the new module against the sampling performance of dual packers and a focused probe. This work is directly relevant to the planning and fundamental understanding of wireline fluid sampling. The key contributions are miscible and immiscible contamination cleanup models that include the effect of tool storage, a comprehensive analysis of contamination cleanup behavior for the new-generation WFT module with comparisons against conventional single-probe, focused probe, and dual-packer tools, and a characterization of fluid sampling conditions versus the preferred type of sampling tool. Introduction A logical start for any wireline formation testing (WFT) operation is a tool string design that considers the formation evaluation objectives and expected formation and fluid properties. With the current availability of an arsenal of probes having different shapes, focused probes of circular or elongated design, and dual packers, this planning stage has now become a more complex process. The recently introduced 3D radial probe (Al Otaibi et al. 2012; Flores de Dios et al. 2012) adds another choice for the engineers in planning WFT surveys. Successful WFT operations demand that toolstrings be designed to meet specific formation and fluid challenges (Weinheber et al. 2008). The selected downhole pump and probe or dual-packer combination must be able to induce and maintain flow from the formation without causing excessive drawdown to stay above expected phase-separation envelope. It must achieve and keep a seal with the borehole face and must not plug during the cleanup operation. While achieving these performance goals, it must work effectively with the downhole pump to deliver high rates that reduce cleanup time. For transient testing, the tool system must have a small storage volume, flow should be smooth and stable, and buildup transients should be free of bore-hole or tool-induced noise. A major challenge for downhole sampling and downhole fluid analysis (DFA) is mud filtrate contamination. Acquired samples must be of sufficiently low contamination for reliable laboratory analysis, as well as better DFA. High miscible contamination (oil/gas and oil-based mud filtrate, water and water-based mud filtrate) or emulsions formed in immiscible fluids (oil and water-based mud filtrate, or water and oil-based mud filtrate) can make acquired samples unusable and reliable DFA may not be possible. Knowledge of tool interaction with the sandface, pump selection, flowing time and rate, and

Integration of Downhole Fluid Analysis and the Flory-Huggins-Zuo EOS for Asphaltene Gradients and Advanced Formation Evaluation

Abstract The Yen-Mullins model of asphaltenes has enabled the development of the industry’s first asphaltene equation of state (EOS) for predicting asphaltene concentration gradients in oil reservoirs, the Flory-Huggins-Zuo (FHZ) EOS. The FHZ EOS is built on the existing the Flory-Huggins regular solution model, which has been widely used in modeling the phase behavior of asphaltene precipitation in the oil and gas industry. For crude oil in reservoirs with a low gas/oil ratio (GOR), the FHZ EOS reduces predominantly to a simple form—the gravity term only—and for mobile heavy oil, the gravity term is simply based on asphaltene clusters. The FHZ EOS has been applied to different crude oil columns from volatile oil to black oil to mobile heavy oil all over the world to address key reservoir issues such as reservoir connectivity/compartmentalization, tar mat formation, nonequilibrium with a late gas charge, and asphaltene destabilization by integrating downhole fluid analysis (DFA) measurements and the Yen-Mullins model of asphaltenes. Asphaltene or heavy-end concentration gradients in crude oils are treated using the FHZ EOS explicitly incorporating the size of resin molecules, asphaltene molecules, asphaltene nanoaggregates, or/and asphaltene clusters. Field case studies proved the value and simplicity of this asphaltene or heavy-end treatment. Heuristics can be developed from results corresponding to the estimation of asphaltene gradients. Perylene-like resins with the size of ~1 nm are dispersed as molecules in high-GOR light oils (condensates) with high fluorescence intensity and without asphaltenes (0 wt% asphaltene). Heavy asphaltene-like resins with the size of ~1.5 nm are molecularly dissolved in volatile oil at very low asphaltene content. Asphaltene nanoaggregates with the size of ~2 nm are dispersed in stable crude oil at a bit higher asphaltene content. Asphaltene clusters are found in mobile heavy oil with the size of ~5 nm at even higher asphaltene content (typically >8 wt% based on stock-tank oil). All these studies are in accord with the observations in the Yen-Mullins model within the FHZ EOS analysis. Furthermore, the cubic EOS and FHZ EOS have been extended to a near critical fluid column with GOR changing from 2600 to 5600 scf/STB and API gravity changes from 34 to 41 °API. Data from the real-time third-generation of DFA were used to establish the early time EOS for advanced formation evaluation. The early-time EOS was updated after the laboratory PVT data were available. The results from the early-time EOS based on the new-generation DFA data were in accord with those from the updated one based on the pressure/volume/temperature (PVT) data. The large GOR gradient is well modeled by the cubic EOS assuming a small late gas charge from the crest to the base. The FHZ EOS with 1-nm diameter was employed to predict the fluorescence intensity gradient. This agrees that perylene-like resins with the size of ~1 nm are dispersed as molecules in high-GOR light oil (rich gas condensate) with high fluorescence intensity and without asphaltenes (0 wt% asphaltene).