Tang, B. (The University of Texas At Austin) | Anand, N. (The University of Texas At Austin) | Nguyen, B. (The University of Texas At Austin) | Sie, C. (The University of Texas At Austin) | Verlaan, M. (Shell) | Díaz, O. Castellanos (Canadian Natural Resources Ltd.) | Nguyen, Q. P. (The University of Texas At Austin)
The Vapor-Oil Gravity Drainage (VOGD) is a low temperature, solvent-enhanced gas-oil gravity drainage (GOGD) process targeting naturally fractured viscous reservoirs. The experimental set up and corresponding acquired data was previously introduced by the authors (Anand et al., 2017) in which the effects of temperature, solvent injection rate, and solvent type (n-Butane and dichloromethane (DCM)) were investigated. Results from Anand et al. work indicated encouraging high oil rates and ultimate recoveries; results also demonstrated that the oil rates and recovery were impacted by diffusion and dispersion (in the form of intrinsic gas rate), asphaltene precipitation, and capillary pressure. The intent of this work is to further study the mechanisms behind VOGD; in particular those related to operating pressure and solvent vapor-oil capillary pressure. The results from this work show that the ultimate recovery and oil rate are positively correlated to the operating pressure; experiments conducted at 50% and 75% saturation pressure
Alboudwarej, Hussein (Chevron Energy Technology Company) | Sheffield, Jonathan M. (Chevron Energy Technology Company) | Srivastava, Mayank (Chevron Energy Technology Company) | Wu, Stanley S. (Chevron Energy Technology Company) | Zuo, Lin (Chevron Energy Technology Company) | Inouye, Arthur (Chevron Energy Technology Company) | Zhou, Dengen (Chevron Energy Technology Company) | Oghena, Andrew (Chevron Energy Technology Company)
Standard gas Enhanced Oil Recovery (EOR) Pressure-Volume-Temperature (PVT) program includes experiments such as solubility/swelling, multi-contact, slim tube, vapor-liquid equilibria (VLE) tests, and fluid property measurements. These tests are designed to determine the extent of gas miscibility and mixture phase behavior during gas injection in hydrocarbon reservoirs. These experimental programs are known to be expensive and time consuming. The degree of complexity increases as the industry move into conducting gas EOR PVT for high/ultra-high-pressure reservoirs. The focus of this paper is to demonstrate the challenges associated with these measurements and evaluate the merit, applicability, and usage of such data for fluid model development for high pressure gas EOR studies.
Associated challenges include utilizing gas concentrations up to 90% mole during swelling tests to determine critical mixture composition. Determination of dew point pressures by visual inspection or liquid build-up method proved inefficient. An interpretation of pressure-volume data showed good promise for determining both saturation pressure and liquid build-up curve for opaque dew point systems. VLE tests were designed at gas concentrations close to critical mixture composition to generate phases with increased affinity for mass transfer. Measured Minimum Miscibility Pressure (MMP) for all studied oil and gas systems were less than 6000 psia, except for N2 gas. Such relatively low MMP values suggest that development of full miscibility is not a concern for these high-pressure fluid systems. Such relatively low MMP values suggest that generated miscibility is not a concern for these high-pressure fluid systems. Instead the focus shifted to determine and effectively model the first contact miscibility pressures for these fluid systems (if it existed at pressures less than initial reservoir pressure). Measured MMPs were assigned a low weight factor in EoS model optimization process. Swelling test data for gas concentrations lower than 50% mole was of little value for EoS model optimization. Presence of precipitated asphaltenes challenged accurate measurement of liquid phase density and viscosity, as capture and analysis of a representative sample was very difficult. A knowledge of asphaltenes phase envelope for mixtures of reservoir fluid and injection gas proved to be invaluable.
A robust gas EOR PVT database was generated for mixtures of 6 injection gases and 7 deep water Gulf of Mexico Wilcox Trend reservoir fluids. Tests were carried out at pressures as high as 20000 psia and temperatures ranging between 230-265 °F. New high-pressure testing capabilities were developed, and modified data interpretation techniques were implemented. Lessons learned during the measurement, interpretation and application of these high-pressure gas EOR PVT data helped us design an effective measurement program. The developed fit-for-purpose experimental program leads to reduced cost (elimination of unnecessary tests) and increased reliability of high pressure phase equilibria and fluid property data for gas EOR reservoir simulation studies.
Luo, Haishan (The University of Texas at Austin) | Mohanty, Kishore K. (The University of Texas at Austin) | Delshad, Mojdeh (The University of Texas at Austin) | Pope, Gary A. (The University of Texas at Austin)
Upscaling of unstable immiscible flow remains an unsolved challenge for the oil industry. The absence of a reliable upscaling approach greatly hinders the effective reservoir simulation and optimization of heavy oil recoveries using waterflood, polymer flood and other chemical floods, which are inherently unstable processes. The difficulty in upscaling unstable flow lies in estimating the propagation of fingers smaller than the gridblock size. Using classical relative permeabilities obtained from stable flow analysis can lead to incorrect oil recovery and pressure drop in reservoir simulations.
In a recent study based on abundant experimental data, it is found that the heavy-oil recovery by waterfloods and polymer floods has a power-law correlation with a dimensionless number (named viscous finger number in this paper), which is a combination of viscosity ratio, capillary number, permeability, and the cross-section area of the core. Based upon this important finding as well as the features of unstable immiscible floods, an effective-finger model is developed in this paper. A porous medium domain is dynamically identified as three effective zones, which are two-phase flow zone, oil single-phase flow zone, and bypassed oil (isolated oil island) zone, respectively. Flow functions are derived according to effective flows in these zones. This new model is capable of history-matching a set of heavy-oil waterflood corefloods under different viscosity ratios and injection rates. Model parameters obtained from the history match also have a power-law correlation with the viscous finger number.
The build-up of this correlation contains reasonable physical meanings to quantitatively characterize the upscaled behavior of viscous fingering effects. Having such a correlation enables the estimation of model parameters in any gridblock of the reservoir by knowing the local viscous finger number in reservoir simulations. The model is applied to several heavy-oil field cases with waterfloods and polymer floods with different heterogeneities. Oil recovery in water flooding of viscous oils is overpredicted by classical simulation methods which do not incorporate viscous fingering properly. Simulation results indicate that the new model reasonably differentiates the oil recoveries at different viscous finger numbers, e.g., lower injection rate leads to higher oil recovery. In contrast, classical simulations obtain close oil recoveries under different injection rates or degrees of polymer shear-thinning, which is apparently incorrect for unstable floods. Moreover, coarse-grid simulations using the new model are able to obtain consistent saturation and pressure maps with fine-grid simulations when the correlation lengths are not smaller than the coarse gridblock size. Furthermore, it is well captured by the model that the shear-shinning polymer solution can strengthen the fingering in high-permeability regions due to increased capillary number and viscosity ratio, which is not observed in waterflood. As a whole, the new model shows encouraging capability to simulate unstable water and polymer floods in heavy oil reservoirs, and hence can facilitate the optimization of heavy-oil EOR projects.