Measurement and modeling of fluid-fluid miscibility in multicomponent hydrocarbon systems

Carbon dioxide injection has currently become a major gas injection process for improved oil recovery. Laboratory evaluations of gas-oil miscibility conditions play an important role in process design and economic success of field miscible gas injection projects. Hence, this study involves the measurement and modeling of fluid-fluid miscibility in multicomponent hydrocarbon systems. A promising new vanishing interfacial tension (VIT) experimental technique has been further explored to determine fluid-fluid miscibility. Interfacial tension measurements have been carried out in three different fluid systems of known phase behavior characteristics using pendent drop shape analysis and capillary rise techniques. The quantities of fluids in the feed mixture have been varied during the experiments to investigate the compositional dependence of fluid-fluid miscibility. The miscibility conditions determined from the VIT technique agreed well with the reported miscibilities for all the three standard fluid systems used. This confirmed the sound conceptual basis of VIT technique for accurate, quick and cost-effective determination of fluid-fluid miscibility. As the fluid phases approached equilibrium, interfacial tension was unaffected by gas-oil ratio in the feed, indicating the compositional path independence of miscibility. Interfacial tension was found to correlate well with solubility in multicomponent hydrocarbon systems. The experiments as well as the use of existing computational models (equations of state and Parachor) indicated the importance of counter-directional mass transfer effects (combined vaporizing and condensing mass transfer mechanims) in fluid-fluid miscibility determination. A new mechanistic Parachor model has been developed to model dynamic gas-oil miscibility and to determine the governing mass transfer mechanism responsible for miscibility development in multicomponent hydrocarbon systems. The proposed model has been validated to predict dynamic gas-oil miscibility in several crude oil-gas systems. This study has related various types of developed miscibility in gas injection field projects with gas-oil interfacial tension and identified the multitude of roles played by interfacial tension in fluid-fluid phase equilibria. Thus, the significant contributions of this study are further validation of a new measurement technique and development of a new computational model for gas-oil interfacial tension and miscibility determination, both of which will have an impact in the optimization of field miscible gas injection projects

Surfactant-induced relative permeability modifications for oil recovery enhancement

Surfactants have been considered for enhanced oil recovery by reduced oil-water interfacial tension. However, these surfactants may enhance oil recovery via wettability alteration as well. This study experimentally determines the influence of surfactant type and concentration on oil recovery, oil-water relative permeabilities and wettability in reservoir rocks. Several coreflood experiments were conducted using Yates reservoir fluids in Berea rocks and two types of surfactants (nonionic and anionic) in varying concentrations. A coreflood simulator was used to calculate oil-water relative permeabilities by history matching recovery and pressure drop measured during the corefloods. These relative permeability variations were interpreted using Craig\u27s rules-of-thumb to characterize wettability alterations induced by the surfactants. The two main mechanisms behind the use of surfactants to enhance oil recovery are (1) reduction in interfacial tension and (2) alteration of wettability. To discern the relative contributions from these two mechanisms on enhanced oil recovery, two series of coreflood experiments have been conducted using a nonionic surfactant in varying concentrations. The first series used decane as the oil phase to quantify the effect of reduction in interfacial tension on oil recovery, while considering wettability effects in the decane-brine-Berea system to be negligible. The second series used Yates crude oil in place of decane to quantify the effects of reduction in interfacial tension as well as wettability alteration on enhanced oil recovery. The same two sets of experiments are then repeated with the anionic surfactant. The comparison of results of these four sets of experiments showed significantly higher oil recoveries for second series of experiments, indicating that the surfactants have altered wettability. The optimum surfactant concentration was found to be 3500 ppm. In three of the four cases studied, oil/water emulsions caused high pressure drops during the flooding experiments, strongly affecting the relative permeability curves. Craig\u27s rules-of-thumb may not be applicable in systems containing emulsions. This study suggests that the development of a mixed-wettability state yields significantly higher oil recoveries observed in Yates crude oil systems. The significant contributions of this study are the quantification of the wettability altering capability of surfactants and the consequent enhancement of oil recovery

Modelling the effects of reservoir parameters and rock mineralogy on wettability during low salinity waterflooding in sandstone reservoirs

Peer reviewedPostprintproo

Response of crude oil deposited organic layers to brines of different salinity:An atomic force microscopy study on carbonate surfaces

The various microscopic processes that take place during enhanced oil-recovery upon injecting low salinity brines are quite complex, particularly for carbonate reservoirs. In this study, we characterize the in-situ microscopic responses of the organic layers deposited on flat Iceland spar calcite surface to brines of different salinity using Atomic force Microscopy (AFM). Organic layers were deposited from crude oil at the end of a two-step aging procedure. AFM topography images reveal that the organic layers remain stable in high-salinity brines and desorb upon exposure to low-salinity brines. In addition, the organic layers swell in low-salinity brines, and the stiffness of the organic layers is found to directly proportional to the brine salinity. These observations are explained in terms of ‘salting-out’ effects, where the affinity of organic layers to solvent molecules increases upon reducing the brine salinity. The swelling and desorption of organic materials provide access for the brine to mineral surface causing dissolution and change in wetting properties of the surface. Our results show the significance of de-stabilizing the organic layer on rock surfaces in order to design any successful improved oil recovery (IOR) strategy

Elastometry of Complex Fluid Pendant Capsules

Oil/water interfaces are ubiquitous in nature. Opposing polarities at these interfaces attract surface-active molecules, which can seed complex viscoelastic or even solid interfacial structure. Biorelevant proteins such as hydrophobin, polymers such as PNIPAM, and the asphaltenes in crude oil (CRO) are examples of some systems where such layers can occur. When a pendant drop of CRO is aged in brine, it can form an interfacial elastic membrane of asphaltenes so stiff that it wrinkles and crumples upon retraction. Most of the work studying CRO/brine interfaces focuses on the viscoelastic liquid regime, leaving a wide range of fully solidified, elastic interfaces largely unexplored. In this work, we quantitatively measure elasticity in all phases of drop retraction. In early retraction, the interface shows a fluid viscoelasticity measurable using a Gibbs isotherm or dilatational rheology. Further retraction causes a phase transition to a 2D elastic solid with nonisotropic, nonhomogeneous surface stresses. In this regime, we use new techniques in the elastic membrane theory to fit for the elasticities of these solid capsules. These elastic measurements can help us develop a deeper understanding not only of CRO interfaces but also of the myriad fluid systems with solid interfacial layers.</p

Time-Dependent Physicochemical Changes of Carbonate Surfaces from SmartWater (Diluted Seawater) Flooding Processes for Improved Oil Recovery.

Over the past few decades, field- and laboratory-scale studies have shown enhancements in oil recovery when reservoirs, which contain high-salinity formation water (FW), are waterflooded with modified-salinity salt water (widely referred to as the low-salinity, dilution, or SmartWater effect for improved oil recovery). In this study, we investigated the time dependence of the physicochemical processes that occur during diluted seawater (i.e., SmartWater) waterflooding processes of specific relevance to carbonate oil reservoirs. We measured the changes to oil/water/rock wettability, surface roughness, and surface chemical composition during SmartWater flooding using 10-fold-diluted seawater under mimicked oil reservoir conditions with calcite and carbonate reservoir rocks. Distinct effects due to SmartWater flooding were observed and found to occur on two different timescales: (1) a rapid (&lt;15 min) increase in the colloidal electrostatic double-layer repulsion between the rock and oil across the SmartWater, leading to a decreased oil/water/rock adhesion energy and thus increased water wetness and (2) slower (&gt;12 h to complete) physicochemical changes of the calcite and carbonate reservoir rock surfaces, including surface roughening via the dissolution of rock and the reprecipitation of dissolved carbonate species after exchanging key ions (Ca2+, Mg2+, CO32-, and SO42- in carbonates) with those in the flooding SmartWater. Our experiments using crude oil from a carbonate reservoir reveal that these reservoir rock surfaces are covered with organic-ionic preadsorbed films (ad-layers), which the SmartWater removes (detaches) as flakes. Removal of the organic-ionic ad-layers by SmartWater flooding enhances oil release from the surfaces, which was found to be critical to increasing the water wetness and significantly improving oil removal from carbonates. Additionally, the increase in water wetness is further enhanced by roughening of the rock surfaces, which decreases the effective contact (interaction) area between the oil and rock interfaces. Furthermore, we found that the rate of these slower physicochemical changes to the carbonate rock surfaces increases with increasing temperature (at least up to an experimental temperature of 75 °C). Our results suggest that the effectiveness of improved oil recovery from SmartWater flooding depends strongly on the formation of the organic-ionic ad-layers. In oil reservoirs where the ad-layer is fully developed and robust, injecting SmartWater would lead to significant removal of the ad-layer and improved oil recovery

Microscopic Characterization of Mineral Dissolution and Precipitation at Variable Salinity for Improved Oil Recovery in Carbonate Reservoirs

Aging of carbonate mineral surfaces in brines of variable salinity and crude oil leads to massive transformations of surface topography and chemical composition including the formation of mixed organic-inorganic interfacial layers. The response of these interfacial layers to variations in brine composition is responsible for local (chemical) wettability alteration and therefore becomes the main microscopic driver for improved oil recovery in low-salinity water flooding or SmartWater flooding. In this study, a new method was developed to directly visualize local nanoscale dissolution and (re)precipitation around the three-phase contact line on model calcite surfaces in the presence of crude oil and ambient brine upon aging. The sessile microscopic oil drops on calcite surfaces were exposed to brines of variable composition at room temperature (22 °C) and at elevated temperatures (95 °C) for up to 2 weeks. Brines ranged from hypersaline formation water to diluted high-salinity water, in part enriched with Mg2+ or SO42- ions. In situ optical and ex situ atomic force microscopy (AFM) imaging of the calcite surfaces was performed prior to and after aging, complemented by confocal Raman imaging. Optical images show that crude oil drops remained attached to the mineral surfaces throughout all aging procedures studied and displayed only occasional minor relaxations of their shape at elevated temperatures. Ex situ AFM images after calcite cleaning and drying displayed strong marks of the original droplet positions that appeared either as holes or as protruding mesas with respect to the surrounding surface level, with height differences up to several hundred nanometers. The sessile oil drops are thus found to protect the underlying calcite surface from both precipitation and dissolution, in overall agreement with the macroscopic calcite saturation of the brines. The qualitative trends are consistent for all conditions investigated, notwithstanding a higher degree of variability at elevated temperatures and upon preaging in oil-equilibrated formation water. In contrast to the calcite-brine interface that undergoes these massive transformations, the oil-calcite interface remains overall remarkably inert. Only at 95 °C does the occasional appearance of roundish rims accompanied by hillocks suggest the growth of water drops during aging, possibly via exchange across thin aqueous layers.</p

Absence of anomalous underscreening in highly concentrated aqueous electrolytes confined between smooth silica surfaces

Recent surface forces apparatus experiments that measured the forces between two mica surfaces and a series of subsequent theoretical studies suggest the occurrence of universal underscreening in highly concentrated electrolyte solutions. We performed a set of systematic Atomic Force Spectroscopy measurements for aqueous salt solutions in a concentration range from 1 mM to 5 M using chloride salts of various alkali metals as well as mixed concentrated salt solutions (involving both mono- and divalent cations and anions), that mimic concentrated brines typically encountered in geological formations. Experiments were carried out using flat substrates and submicrometer-sized colloidal probes made of smooth oxidized silicon immersed in salt solutions at pH values of 6 and 9 and temperatures of 25 °C and 45 °C. While strong repulsive forces were observed for the smallest tip-sample separations, none of the conditions explored displayed any indication of anomalous long range electrostatic forces as reported for mica surfaces. Instead, forces are universally dominated by attractive van der Waals interactions at tip-sample separations of ≈2 nm and beyond for salt concentrations of 1 M and higher. Complementary calculations based on classical density functional theory for the primitive model support these experimental observations and display a consistent decrease in screening length with increasing ion concentration

Development and Optimization of Gas-Assisted Gravity Drainage (GAGD) Process for Improved Light Oil Recovery

This is the final report describing the evolution of the project ''Development and Optimization of Gas-Assisted Gravity Drainage (GAGD) Process for Improved Light Oil Recovery'' from its conceptual stage in 2002 to the field implementation of the developed technology in 2006. This comprehensive report includes all the experimental research, models developments, analyses of results, salient conclusions and the technology transfer efforts. As planned in the original proposal, the project has been conducted in three separate and concurrent tasks: Task 1 involved a physical model study of the new GAGD process, Task 2 was aimed at further developing the vanishing interfacial tension (VIT) technique for gas-oil miscibility determination, and Task 3 was directed at determining multiphase gas-oil drainage and displacement characteristics in reservoir rocks at realistic pressures and temperatures. The project started with the task of recruiting well-qualified graduate research assistants. After collecting and reviewing the literature on different aspects of the project such gas injection EOR, gravity drainage, miscibility characterization, and gas-oil displacement characteristics in porous media, research plans were developed for the experimental work to be conducted under each of the three tasks. Based on the literature review and dimensional analysis, preliminary criteria were developed for the design of the partially-scaled physical model. Additionally, the need for a separate transparent model for visual observation and verification of the displacement and drainage behavior under gas-assisted gravity drainage was identified. Various materials and methods (ceramic porous material, Stucco, Portland cement, sintered glass beads) were attempted in order to fabricate a satisfactory visual model. In addition to proving the effectiveness of the GAGD process (through measured oil recoveries in the range of 65 to 87% IOIP), the visual models demonstrated three possible multiphase mechanisms at work, namely, Darcy-type displacement until gas breakthrough, gravity drainage after breakthrough and film-drainage in gas-invaded zones throughout the duration of the process. The partially-scaled physical model was used in a series of experiments to study the effects of wettability, gas-oil miscibility, secondary versus tertiary mode gas injection, and the presence of fractures on GAGD oil recovery. In addition to yielding recoveries of up to 80% IOIP, even in the immiscible gas injection mode, the partially-scaled physical model confirmed the positive influence of fractures and oil-wet characteristics in enhancing oil recoveries over those measured in the homogeneous (unfractured) water-wet models. An interesting observation was that a single logarithmic relationship between the oil recovery and the gravity number was obeyed by the physical model, the high-pressure corefloods and the field data