Microscopic Oil Displacement Efficiency Research Articles

The Time-Varying Characteristics of Relative Permeability in Oil Reservoirs with Gas Injection

Relative permeability is a critical parameter in reservoir numerical simulation and production prediction, intimately associated with reservoir architecture and fluid property. During gas injection development, substantial alterations in reservoir properties and fluid phase behavior induce dynamic changes in relative permeability. Clearly characterizing the time-varying features of relative permeability is very useful for an understanding of how gas injection influences fluid mobility within the reservoir and enhances recovery rates. In this paper, core displacement experiments are firstly conducted to obtain the characteristics of the relative permeability of oil and gas under various development stages and displacement conditions, further delineating the comprehensive shifts in reservoir properties at different gas injection stages. Subsequently, a novel reservoir numerical simulation method is proposed that considers the spatial and temporal segmentation of relative permeability curves in the reservoir simulation. Finally, a practical application is presented to clarify the effects of injection and production parameters on the development performance of gas flooding oil reservoirs. The results show the following: (i) Significant time-varying characteristics of relative permeability occur throughout gas injection development, in the early stages of gas injection, where most of the reservoir is at the gas injection front, and a rightward shift in relative oil and gas permeability indicates that gas injection promotes oil mobility. Conversely, in the later stages of gas injection, as the reservoir reaches the trailing edge of gas injection, the change trend in relative oil and gas permeability reverses, shifting leftward, thereby exacerbating the gas breakout phenomena. (ii) Increasing the rate of gas injection causes relative oil and gas permeability to move leftward, effectively enhancing the gas volume sweep coefficient and microscopic oil displacement efficiency at lower injection speeds while reducing development performance at higher injection speeds. (iii) An increase in gas injection pressure causes relative oil and gas permeability to shift rightward, and although it reduces residual oil saturation and enhances microscopic oil displacement efficiency, it also intensifies gas breakout phenomena and lowers the gas volume sweep coefficient. This paper provides theoretical guidance and technical support for the design of gas injection strategies, optimization of injection and production parameters, and production forecasting.

Combination of nano-bentonite stabilized foam and ultra-low IFT surfactant additives assisted steam injection to enhanced heavy oil recovery

This study presents an experimental investigation of combination of nano-bentonite stabilized foam and surfactant additives with ultra-low interfacial tension (IFT) to enhance thermal recovery of heavy oil by steam injection. The foam stability results showed that the nano-bentonite can form a three-dimensional network structure to increase the viscosity and thickness of the liquid film, and thus significantly improving the foam stability at high temperature. The foam resistance factor determination demonstrated that the nano-bentonite stabilized foam has good selective plugging ability of reducing the mobility of steam to inhibit the steam channeling. The surfactant additives prepared by the composite system of sodium dodecyl benzene sulfonate and sodium nonylphenol polyoxyethylene ether sulfonate can achieve synergistic effect of high interfacial activity and high-temperature resistance, which can reduce the oil–water interfacial tension to ultra-low level at high temperature. The heterogeneous sandpack flooding results indicated that the nano-bentonite stabilized foam can effectively block the steam channels to improve the sweep efficiency of steam injection and the ultra-low IFT surfactant additives can greatly increase the microscopic oil displacement efficiency. And thus the combination of nano-bentonite stabilized foam and the ultra-low IFT surfactant additives can significantly enhance thermal oil recovery of steam injection in heavy oil reservoirs.

Numerical Modeling on the Influence of Effective Porosity, Microbial Kinetics, and Operational Parameters on Enhanced Oil Recovery by Microbial Flooding Within a Sandstone Formation

Summary During the implementation of a microbial-enhanced-oil-recovery (EOR) (MEOR) technique in a sandstone formation, various reservoir physicochemical, microbial kinetic, and operational parameters play major roles in governing the efficiency of crude-oil recovery from a hydrocarbon reservoir. The present study numerically investigates the sensitivity of sandstone formation effective porosity; different injected strains of the species Bacillus under optimal metabolic conditions and possessing distinct values of maximum microbial-specific-growth rate, Monod saturation constant, and yield coefficient; and crucial operational parameters on biomass and biosurfactant production and their effects on microscopic oil-displacement efficiency within the sandstone reservoir, along with prompting modifications in rock physicochemical properties. A black-oil biochemical multispecies reactive transport model in porous sandstone media is developed by coupling the kinetic model with the corresponding transport model involving microbial sorption. The governing equations involve coupled transport of nutrients and microbes by dispersion and convection, growth and decay rates of microbes, chemotaxis, nutrient consumption, and deposition of microbes and nutrients on rock-grain surfaces caused by reversible/irreversible sorption. Coupled empirical equations are used to estimate biosurfactant production, oil/water-interfacial-tension (IFT) reduction, change in the viscosity of injection fluid, and their effects on oil relative permeability and mobility, and thus a decrease in residual oil saturation within the reservoir. The finite-difference-discretization technique is adopted to solve the governing equations. Results of the present model are found to be numerically stable and match very well, when verified, with the previously published analytical, numerical, and experimental results. The model results suggest that at very low reservoir porosity (approximately 10%), an early breakthrough of nutrients, microbes, and biosurfactant leave insignificant concentrations in their respective fronts, which are insufficient for the recovery of the trapped oil. Also, increase in porosity to approximately 30% and beyond causes loss of nutrients, microbes, and biosurfactant because they undergo higher dispersion during their transport within the reservoir. Thus, sandstone formations possessing an intermediate effective porosity value of approximately 20% significantly enhance the efficiency of the overall MEOR process. Further, it is observed that the nature of microbes and nutrients used for MEOR application affect biosurfactant production, and in turn oil recovery, to a large extent. Those microbial species with far lower Monod-saturation-constant values have high affinity toward their substrates. This phenomenon dramatically increases the rates of nutrient consumption and production of biomass and biosurfactant within a reservoir when suitable substrate compounds are used, irrespective of differences in the yield coefficients of the microbes. Further MEOR simulation studies within a sandstone core exhibited maximum oil displacement and recovery at a run time of 5 hours, injected-microbial concentration of 4.32×10–3 mg/cm3, and maximum specific growth rate of 0.35 hours–1. Bioplugging-induced formation damage negatively affecting the oil-recovery efficiency is also observed with an increase in the process run time. The screened microbe also exhibited the possibility of wettability alteration of sandstone-formation rock from mixed/oil-wet to water-wet. Thus, the present study provides an improved understanding of the combined effects of reservoir porosity, microbial kinetic, and key operational parameters on fundamental MEOR processes, which will better characterize and develop an effective strategy to determine the suitability of an MEOR technique in a typical sandstone reservoir. Moreover, the developed numerical model is easier to implement and produces faster results with relatively lower computational cost, which helps in making a quick decision before applying MEOR processes in the field.

Mechanics of SAGD Efficiency Improvement Using Combination of Chemicals: An Experimental Analysis through 2D Visual Models

Summary Steam-assisted gravity drainage (SAGD) is (and will be) a dominating method for in-situ recovery of heavy oil and bitumen in Canada. Its efficiency, however, has been a chronic problem due to the excess use of water and energy causing inflated costs. Solutions are needed to both maintain the production, especially at the late stages, and reduce the amount of steam. One method to improve efficiency is injection of chemicals with steam. This study addresses this problem by focusing on three critical aspects of SAGD: sweep improvement (faster and larger chamber growth), better displacement efficiency (lower residual oil), and reducing the amount of steam (lower steam/oil ratio and lowered steam temperature). By addressing these issues, we provide answers for the proper formulation of chemical blends, optimal injection strategies (continuous or slug), and the right time to introduce chemicals (beginning, midstream, or mature phase). The efficiency of a single chemical additive in recovery improvement is limited because it serves for only one of the mechanisms previously listed. For a better performance, blending chemicals with different functionalities was proposed in this study. Additives showing the highest microscopic oil displacement efficiency (heptane, Novelfroth® 190) and the highest areal sweep efficiency EA [LTS-18, silicon dioxide (SiO2) nanoparticle, Tween™ 80, deep eutectic solvent (DES) 11] in our previous studies were selected. Eleven different combinations of these six chemical additives were tested for different injection strategies, and the SAGD process was visualized on Hele-Shaw cells filled with heavy oil. The interaction between different chemical additives was determined by analyzing emulsification, wettability alteration, and the growth and shape of the steam chamber. The optimal formulation and ideal injection strategy were selected by analyzing ultimate EA, microscopic oil displacement efficiency, ultimate oil recovery, energy and water consumption, and the price of chemical additives. The interaction rule of combined chemical additives and their contribution to the recovery during SAGD were clarified, and the optimal injection strategies (best blends and proper time to introduce chemicals) were identified to provide a reference for chemical selection for field applications. This is a critical attempt to reduce the steam/oil ratio (particularly the amount of steam used) in SAGD applications, especially at mature stages.

Experimental investigation on improved heavy oil recovery by air assisted steam injection with 2D visualized models

Heavy oil reserves play an important role in world’s energy supply. Steam injection is among the most widely used thermal recovery methods for heavy oil recovery. However, the disadvantages such as low oil recovery, high energy consumption and large greenhouse gas emissions, etc. limited the application of this technology. The hybrid injection of steam and air is considered as an effective alternative for pure steam injection. In this paper, a two-dimensional visualized model filled with glass beads was introduced to quantitatively investigate the sweep efficiency and steam channeling of steam and steam/air injection for a typical heavy oil from a macroscopic perspective. On the basis of the experiments, pore-scale analysis was performed to study the enhanced oil recovery mechanisms of steam/air injection. The experimental results indicated that the injected continuous air was cut off into small gas bubbles to form Jamin effect in porous media, along with the react between air and heavy oil to increase the macroscopic sweep efficiency and microscopic oil displacement efficiency. The sweep efficiency and oil recovery of steam/air injection was 90.22% and 61.87%, respectively, which were 22.26% and 10.67% higher than those of pure steam injection.

Pore-scale investigation of residual oil displacement in surfactant–polymer flooding using nuclear magnetic resonance experiments

Research on the Gangxi III area in the Dagang Oilfield shows that there was still a significant amount of oil remaining in oil reservoirs after many years of polymer flooding. This is a potential target for enhanced oil recovery (EOR). Surfactant–polymer (SP) flooding is an effective chemical EOR method for mobilizing residual oil and improving displacement efficiency macroscopically, but the microscopic oil displacement efficiency in pores of different sizes is unclear. Nuclear magnetic resonance (NMR) is an efficient method for quantifying oil saturation in the rock matrix and analyzing pore structures. In this paper, the threshold values of different pore sizes were established from the relationship between mercury injection curves and NMR T 2 spectrums. The distribution and migration of residual oil in different flooding processes was evaluated by quantitatively analyzing the change of the relaxation time. The oil displaced from pores of different sizes after the water flood, polymer flood, and the SP flood was calculated, respectively. Experimental results indicate that (1) the residual oil in medium pores contributed the most to the incremental oil recovery for the SP flood, ranging from 40 % to 49 %, and small pores usually contributed <30 %; (2) the residual oil after the SP flood was mainly distributed in small and medium pores; the residual oil in medium pores accounted for 47.3 %–54.7 %, while that trapped in small pores was 25.7 %–42.5 %. The residual oil in small and medium pores was the main target for EOR after the SP flood in oilfields.

Numerical modelling of enhanced oil recovery by microbial flooding under non-isothermal conditions

In the present paper an attempt has been made to develop an improved numerical model in order to simulate the oil recovery by microbial flooding under non-isothermal conditions. The proposed model simulates the coupled heat and mass transfer resulting from the mobility of microbes along with its nutrients in a typical petroleum reservoir against the conventional isothermal conditions. The model results have been verified with the existing analytical and experimental results. The present model evaluates the optimum mean fluid velocity in order to achieve the maximum oil displacement under different reservoir temperature conditions. The model also investigates the change in relative permeability of oil and water during microbial flooding within the reservoir under non-isothermal conditions and subsequently estimates the residual oil recovery. The model results suggest that the microscopic oil displacement efficiency increases with the increase in mean fluid velocity and reaches a threshold maximum oil displacement just before the water breakthrough at a relatively lower temperature. In addition, it is observed that the maximum oil displacement efficiency of 82.75% is achieved at a reservoir temperature of 60 °C and at an optimum mean fluid velocity of 1.68 m/day in a sandstone reservoir of length 50 m. • Developed a numerical model to evaluate MEOR process under non-isothermal conditions. • Heat distribution in reservoir impacts microbial growth, viscosity of water and oil. • Transport of nutrients and microbes within reservoir is coupled with Monod kinetics. • Studied the impact of reservoir temperature and mean fluid velocity on K rw , K ro . • Evaluated oil displacement efficiency of MEOR under different reservoir conditions.

The impact of extensional viscosity on oil displacement efficiency in polymer flooding

The flow behavior of polymer flooding solution can not only be described simply with shear flow field, but also with convergent and extensional flow field. The extensional viscosity of polymer solutions used in polymer flooding in Daqing Oilfield was investigated with CaBER1 extensional rheometer, and the results showed that the extensional viscosity of which is much higher than shear viscosity with three orders of magnitude. The extensional viscosity of the polymer solutions sharply increased when polymer molecules were stretched to the limit, which means that an extension stiffen phenomenon occurred. The extremely high extensional viscosity and an extension stiffen characteristic in stretching process of polymer solutions could increase capillary number substantially to raise microscopic oil displacement efficiency.

Microbial selective plugging and enhanced oil recovery

The ability of indigenous populations of microorganisms in Berea sandstone to improve the volumetric sweep efficiency and increase oil recovery by in situ growth and metabolism following the injection of nutrients was studied. Cores of differing permeabilities connected in parallel without crossflow and slabs of sandstone with differing permeabilities in capillary contact to allow crossflow were used. The addition of a sucrosenitrate mineral salts medium stimulated the growth and metabolism of microorganisms in the sandstone systems. This resulted in a preferential decrease in permeability in the core or slab with the higher initial permeability, diverted flow into the lower-permeability core or slab and improved the volumetric sweep efficiency. Injectivity into the slab with the lower initial permeability in the crossflow system increased during subsequent nutrient injections. Thus, microbial selective plugging does occur in laboratory systems that have the complex flow patterns observed in petroleum reservoirs without losing the ability to inject fluids into the formation. In situ microbial growth and metabolism increased oil recovery 10 to 38% of the original oil in place. Biogenic gas production accompanied oil production, and much of the gas was entrained within the produced oil suggesting that gas production was an important factor leading to increased oil recovery. Quantitation of the amount of phospholipid in the core confirmed that microbial growth preferentially occurred throughout the core with the higher initial permeability. These data showed that in situ microbial growth in the high-permeability regions improved not only the volumetric sweep efficiency but also the microscopic oil displacement efficiency.