Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Abstract Wettability alteration considered as the principal mechanism has attracted more attention for low salinity waterflooding effect. It was significantly affected by electrokinetic interactions, which occurred at the interfaces of rock/brine and crude oil/brine. The mineral impurities of natural carbonate releasing ions have an important impact on the electrokinetics, which could lead to wettability shift subsequently. In this study, the effect of dolomite and anhydrite as the main impurities in natural carbonate, which caused wettability alteration, was evaluated using triple-layer surface complexation and thermodynamic equilibrium models coupled with extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. The electrokinetics of crude oil and carbonate in brines were predicted by the triple-layer surface complexation model (TLM) based on zeta potential, while thermodynamic equilibrium model was mainly used for analyzing the carbonate impurities on wettability alteration. The equilibrium constants of reactions were determined by successfully fitting the calculated zeta potentials with measured ones for crude oil and carbonate in different solutions, which were validated for zeta potential prediction in smartwater. The disjoining pressure results show that there is a repulsion between crude oil and carbonate in Na2SO4 brine (Brine3) or smartwater (Brine4) equilibrating with calcite when comparing to that in MgCl2 (Brine1) and CaCl2 (Brine2), indicating the water-wet condition caused by the presence of sulphate ions. Moreover, the equilibrium of carbonate impurities with smartwater increases the repulsion between oil and carbonate. When the sulphate ion concentration in the adjusted smartwater exceeds a certain value, the effect of carbonate impurities on wettability alteration is not significant. Finally, the influence of smartwater pH on the interaction between oil and carbonate was evaluated with or without considering the equilibrium of carbonate impurities.
- North America > United States (0.68)
- Europe (0.46)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Sulfate (0.79)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.51)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.46)
Abstract The wettability alteration is the most prominent mechanism for a favorable effect of low salinity water flooding in enhanced oil recovery. It has been accepted that the surface charge at crude oil/brine and rock/brine interfaces significantly influences the interaction of the crude oil with rock surface and thus wettability changes. In this study, the interface characteristics were coupled with a solute transport model to simulate low salinity waterflooding in carbonate and sandstone reservoirs. The ionic transport and two- phase flow of oil and water equations were solved and coupled with IPhreeqc for geochemical calculations. The dissolution and precipitation of minerals were considered thorough thermodynamic equilibrium reactions in IPhreeqc. In addition, a triple layer surface complexation model was employed in IPhreeqc to predict electrokinetic properties of crude oil/brine and rock/brine interfaces. The wettability alteration was calculated based the adsorbed polar components of crude oil on minerals’ surface, which changes the relative permeability. The coupled model able to predict the spatiotemporal variation of ionic profiles, surface and zeta potentials, dissolution and precipitation of minerals, total disjoining pressure, and wettability index in addition to oil recovery for the injection of brines. The validity of the coupled model results was tested against PHREEQC in a single-phase flow without the presence of oil. Moreover, the modelling results were compared with the published experimental data for a single-phase flow in carbonate cores. A very good agreement between experimental data and modelling results was obtained. Furthermore, the coupled model was applied to predict ionic concentration, pH profile, and oil recovery in both carbonate and sandstone cores and verified with experimental data. The modelling results reproduce well the experimental data, suggesting that model captures the geochemical and interface reactions. Finally, the coupled model can be used to optimize brine composition for improved oil recovery in carbonate and sandstone reservoirs.
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
Abstract This paper presents a new wettability alteration model based on surface complexation theory and an extensive experimental dataset. The objective is to provide a general correlation for contact angle calculation that (1) captures the main mechanisms that impact rock-brine-oil wettability and (2) minimizes the number of parameters used to tune with experimental data. We compile a set of 141 zeta-potential and contact-angle measurements from the literature. We study the oil/rock surface-complexation reactions and model the electrostatic behavior of each data point. We develop a new wettability model that estimates the contact angle and consists of five terms based on the Young-Laplace equation. We use the Nelder-Mead optimization algorithm to determine the model-parameter values that produce the best fit of experimental observations. The contact angle estimates produced by our model are also verified against those calculated by Extended-Derjaguin-Landau-Verwey-Overbeekand (EDLVO) theory and are validated using UTCOMP-IPhreeqc to simulate five limestone Amott tests from the literature. The Blind-testing test reveals that our model is predictive of the experimental data (R = 0.81, RMSE = 12.5). While reducing the tuning parameters by half, our model is comparable to and–in some cases–even superior to the EDLVO modeling in predicting the contact angle measurements. We argue that EDLVO modeling has 10+ parameters, and the individual errors associated with each parameter could lead to wrong predictions. Amott-test simulations show excellent agreement between the proposed wettability-alteration model and experimental data. The rock's initial wettability was measured to be strongly oil-wet, with a negative Amott index and recovery factor around 5%, corroborating the calculated contact angle of 160 degrees. The recovery factor increases to about 20-35% as the rock becomes more water-wet after interaction with engineered water (contact angle changes to 90-64 degrees). Further analysis indicates the proposed model's capability to capture significant wettability-alteration trends. For example, we report increased water-wetting as brine ionic strength decreases, depicting the low-salinity effect. In addition, our model resulted in better convergence in some of the simulated core floods compared to EDLVO modeling. We conclude that our physics-based and data-driven model is a practical and efficient approach to predict rock-brine-oil wettability.
- Geology > Geological Subdiscipline (1.00)
- Geology > Mineral (0.69)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.48)
- North America > United States > Alaska > North Slope Basin > Duck Island Field > Endicott Field > Kekiktuk Formation (0.99)
- North America > United States > Texas (0.89)
- Europe > United Kingdom > North Sea (0.89)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (0.67)
Abstract Despite the plethora amount of research have been conducted on the Low Salinity Water Injection (LSWI) and the pertinent mechanisms, this Enhanced Oil Recovery (EOR) method still seems not to be well understood. Although the rock/fluid interactions are used to be highlighted as the main elements of chemical mechanism of LSWI, fluid/fluid interactions have been brought into attentions much more than anytime before. Formation of microdispersion within the crude oil phase leading to wettability alteration has been proposed repeatedly as the underlying mechanism of LSWI without clarifying the functional compounds of crude oil toward this EOR method. Discovering the responsible compounds of crude oils towards Low Salinity Water (LSW) and formation of microdispersion is demanding to achieve a reliable screening tool of oil reservoir toward LSWI. For this purpose, the crude oils and brines were contacted for an extended period of time until the oil/water interface reached an equilibrium state right before taking crude oil samples from the interface. The Karl Fischer titration (KFT) analyses were carried out to quantify the amount of microdispersion within the crude oil phase. The crude oil sample with the strongest propensity toward microdispersion formation was further investigated through Fourier Transform Infrared (FT-IR) spectroscopy and Negative Electrospray Ionisation (NESI) mode of Fourier Transform Ion Cyclotron Resonance mass spectroscopy (FT-ICR) to evaluate the chemical compositional changes taking place at the interface due to salinity effect. FT-IR analyses revealed the conjugated acidic compounds or the acidic asphaltenes within the crude oil to be the most functional compounds toward microdispersion formation. Consistently, the NESI mode of FT-ICR MS suggested the carboxylic acids (with C=O functional groups) promoting the formation of microdispersion when the crude oil is swept by LSW. Also highlighted was the structure of functional carboxylic acids during LSWI that appeared to be those compounds with DBE of 1, 2, and 3 and carbon number of C15-C20. The results of this study represent an important step toward understanding the mechanism responsible for the LSE. The knowledge will help the oil and gas industry in the task of evaluating and ranking oil reservoirs for EOR by LSWI.
- North America > United States (0.93)
- Europe > United Kingdom (0.68)
- Geology > Geological Subdiscipline (0.69)
- Geology > Mineral (0.68)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.94)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.62)
Abstract Injection of modified salinity brines modified salinity brines (MSB), i.e. brine with seawater-like salinity (SWS) and low salinity water (LSW) in oil-wet carbonate rocks is relevant to improved oil recovery operations. Many reports in the literature relate the underlying mechanisms to rock-fluid interactions such as ionic exchange and electrical double layer expansions, which cause wettability alterations at the rock surface. Little attention seems to have been placed on fluid-fluid interactions as a potential mechanism in displacement processes. In this work, we investigate the role of fluid-fluid interactions in improved oil recovery using MSBs. Interfacial tension and surface elasticity calculations are correlated to visual observations of displacement processes to investigate the role of crude oil snap-off. A series of microfluidic chips featuring pore throats that are 50μm in diameter are used to observe snap-off as a function of salinity in the displacing fluid. The flow experiments suggest that, in a water-wet constricted pore throat, SWS brines suppress crude oil snap-off as compared to FWS brine. This behavior is correlated to the higher surface elasticity of oil-SWS interface than that of oil-FWS interface. Higher surface elasticity suppresses the expansion of the thin water film coating pore throat walls and hence increases the capillary number at which snap-off of the crude oil phase is expected to occur. Moreover, water interacts with the polar components to form reverse micelles called microdispersions. These microdispersions are observed in the aged chip near the oil-brine interface in the pore-network of a microfluidic device. Similarly, in a vial test performed by Tetteh and Barati, (2019), microdispersion formation was only observed very close to the oil-brine interface, caused by the transport of water molecules into the oil phase. These microdispersions remobilize and redistribute the oil, and along with a slight change in wettability in the medium, they improve the observed recovery. In the pore-network flow experiments, the use of SWS brines resulted in the formation of relatively larger oil droplets, which is attributable to the suppression of crude oil snap-off and enhanced oil coalescence resulting from changes in oil-brine interfaces. The integrated experimental study presented in this work demonstrates the importance of fluid-fluid interactions in improved oil recovery using MSBs.
- Geology > Mineral (0.93)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.36)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.46)
Abstract Understanding the injection water chemistry effect, in terms of both salinity and ionic composition, is becoming crucial to increase oil recovery from waterflooding in carbonate reservoirs. Various studies have shown that that surface charge alteration is the main mechanism behind favorable wettability changes toward water-wet conditions observed during the injection of controlled ionic composition water in carbonates. Therefore, the synergistic coupling between multiphase transport and electrokinetics of brine/calcite and brine/crude oil interfaces becomes important to optimize injection water compositions for enhanced oil recovery in carbonates. In this investigation, the electrokinetic interactions of brine and crude oil in carbonates are accounted for and coupled with the multiphase Darcy flow model. The electrokinetic interactions are parametrized by the zeta-potential values of brine/calcite and crude-oil/brine interfaces, which are determined using a Surface Complexation Model (SCM). The SCM zeta-potential parameters are computed based on the local concentration of aqueous ions that follow the transport equation. The relative permeability and capillary pressure curves are altered based on zeta potential shifts, which resembles the wettability alteration process. The SCM zeta potentials are compared with the experimental zeta-potential measurements, while the multiphase transport model coupled with geochemistry is validated through a comparative coreflood experimental data reported in the literature. The SCM results governed by specified surface geochemical reactions agreed well with zeta-potential measurements obtained at both calcite/brine and crude-oil/brine interfaces. The coupled geochemical SCM with multiphase transport model accurately matched both recovery and pressure drop data from forced imbibition tests reported by Yousef et al. (2011) in both secondary and tertiary modes. The generated relative permeability curves followed Craig's rules in shifting the wettability from oil-wet toward water-wet conditions for advanced waterflooding processes in carbonates. These results confirm the robustness of proposed model based on validated SCM electrokinetic interactions. The development of such a coupled geochemistry based multiphase transport model is an important step to simulate advanced waterflooding processes in carbonates at reservoir scale by taking into account of more representative physicochemical effects. The novelty of this work is that it validates the SCM results with experimental zeta-potential data for different injection water compositions. Also, the applicability of coupled SCM with a multiphase transport model is successfully demonstrated by history matching the experimental coreflood data. The developed model and new findings shed some light on the importance of lower salinity and controlled ionic composition during fluid flow and oil recovery in complex carbonate formations.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Mineral > Carbonate Mineral > Calcite (0.70)
- Geology > Rock Type > Sedimentary Rock (0.68)
Fundamental Investigation of Auto-Emulsification of Water in Crude Oil: An Interfacial Phenomenon and its Pertinence for Low Salinity EOR
Jennifer, Duboué (Total SA) | Maurice, Bourrel (Total SA) | Théo, Dusautoir (Total SA) | Enric, Santanach Carreras (Total SA) | Alexandra, Klimenko (Total SA) | Nicolas, Agenet (Total SA) | Nicolas, Passade-Boupat (Total SA) | François, Lequeux (ESPCI Paris)
Abstract The phenomenon of auto-emulsification occurring when crude oil is gently contacted with water was investigated using various techniques. This spontaneous emulsification which creates a micro-droplet layer at the oil/brine interface is believed to be linked to the improved oil recovery during low salinity Enhanced Oil Recovery (EOR). Crude oils and a model system (asphaltenes solubilized in toluene) have been studied. Observations were facilitated when using the model system, this allowed to have a better insight into the underlying mechanism of micro-droplet formation. It was established that the water micro-droplets appear in the oil phase due to an osmotic phenomenon: molecular water diffuses from the bulk water which provokes the water micro-droplets swelling. The kinetics of the micro-droplet formation is directly linked to the brine salinity in contact with the crude oil: salt addition slows down the emulsification process. This was further confirmed by the evaluation of the water chemical activity in the oil phase from calorimetry measurements. Micromodel experiments showed a higher oil recovery when water micro-droplets are present in the system, irrespective of the initial wettability imposed to the micromodel material. Dilatational rheology measurement did not show significant visco-elasticity arising from the water micro-droplet presence; hence, the visco-elasticity difference cannot completely explain the higher recovery. Manipulation of crude oil droplet during dilatational rheology experiments highlighted the impact of micro-droplets on the shape of the macroscopic oil droplet. The nucleation of micro-droplets at oil/brine or solid/oil interface suggests an explanation for the EOR effect. We have observed that micro-droplets organize at the oil/water interface, while others nucleate at the oil/solid interface or sediment on the solid surface. The interaction of asphaltenes with water molecules dissolved in the oil phase may promote wettability alteration. The micro-droplet formation indicates the magnitude of this interaction for a given asphaltenes/brine system.
- North America > United States (0.46)
- Europe > Norway > Norwegian Sea (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.54)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Precipitates (paraffin, asphaltenes, etc.) (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Downhole chemical treatments and fluid compatibility (0.68)
Abstract Previously proposed models of wettability change have not been tied to the chemistry that controls wettability but instead were driven by simplistic criteria such as salinity level or concentration of an adsorbed species. Such models do not adequately predict the impact of brine compositional change and therefore cannot be used to optimize brine composition. In this work, after testing proposed models in the literature on sandstones and carbonates, we propose a mechanistic surface-complexation-based model that quantitatively describes observations for ionically treated waterfloods. To the best of our knowledge this is the first surface-complexation-based model that fully describes ionic compositional dependence observed in ionically treated waterfloods in both sandstones and carbonates. We model wettability change by directly linking wettability to brine chemistry using detailed colloidal science. Brine has charged ions that interact with polar acidic/basic components at the oil-water interface and rock surface and therefore oil/brine and rock/brine interfaces are charged and exert both Van der Waals and electrostatic forces on each other. If the net result of the forces is repulsive, the thin water film between the two interfaces is stable (i.e., the rock is water-wet) otherwise, the thin water film is unstable and the rock becomes oil-wet. Based on Hirasaki (1991), we describe a ratio of electrostatic force to Van der Waals force with a dimensionless group, called "stability number," where rock wettability is water-wet for values greater than one and oil-wet for values less than one. For sandstones, the zeta potentials of oil/brine and rock/brine interfaces become more negative/less positive by diluting or softening the brine and/or increasing pH. Similarly, for carbonates, dilution and/or sulfate enrichment of brine makes surface potentials more negative. Such brine modification can therefore be used to improve oil recovery. We implemented the improved wettability change model in a comprehensive coupled reservoir simulator, UTCOMP-IPhreeqc, in which oil/brine and rock/brine zeta potentials are modeled using the IPhreeqc surface complexation module. We take into the account total acid number (TAN) and total base number (TBN) for the oil/brine interface and we use rock surface reactions for brine/rock surface potential modeling. Surface potentials obtained from the geochemical model are used to calculate the dimensionless group controlling wettability change, which is dynamically modeled in the transport simulator. The model is validated in sandstones and carbonates by simulating an inter-well test, and several corefloods and imbibition tests reported in the literature. For sandstones, we model Kozaki (2012) and BP's Endicott trial. For simple dilution in carbonates we model experiments by Shehata et al. (2014) and Yousef et al. (2010). For enrichment with sulfate we model Zhang and Austad (2006) and for increasing total ionic strength via sodium chloride enrichment, Fathi et al. (2010a).
- Asia > Middle East (0.67)
- North America > United States > Texas (0.28)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (1.00)
- Geology > Mineral (1.00)
- Geology > Geological Subdiscipline (1.00)
Abstract SmartWater flooding through injection of chemistry optimized waters by tuning individual ions is recently getting more attention in the industry for improved oil recovery in carbonate reservoirs. Most of the research studies described so far in this area have been limited to studying the interactions at rock-fluids interfaces by measuring contact angles, zeta potential, and adhesion forces. The other widely reported interfacial tension data at oil-water interfaces do not consider the formation of interfacial monolayer and the interfacial tension is estimated as an average parameter relying on the properties of two individual bulk phases. As a result, such measurements have serious shortcomings to provide any details on complex microscopic scale interactions occurring directly at the interface between crude oil and water to understand the SmartWater flood recovery mechanism. In this study, two novel interfacial instruments of interfacial shear rheometer and surface potential sensor were used to study microscopic scale interactions of various individual water ions at both air-water and complex crude oil-water interfaces. The measured interfacial rheology data indicated totally different interfacial behavior at crude oil-water interface when compared to air-water interface due to presence of crude oil functional groups. Viscous dominated response was observed at crude oil-water interface for all brine compositions. These interfaces behaved like a viscous fluid without exhibiting viscoelastic solid like properties. Lower interfacial viscous modulus was observed for certain key ions such as calcium, magnesium, and sodium. The interfacial viscous modulus was found to be substantially much higher for sulfates, besides exhibiting some elasticity. The surface potential was gradually decreased by replacing seawater with calcium only brine. The better surface activity with seawater can be attributed to adsorption of more key water ions at the surface. The interesting results observed with certain water ions at fluid-fluid interfaces are expected to work in tandem with rock-fluids interactions to impact oil recovery in SmartWater flood. At first, they play a role to control the accessibility of active water ions to approach the rock surface, interact with it and subsequently alter wettability. Next oil droplets adhering to the rock surface will be detached and released due to favorable interactions occurring at rock-fluids interfaces. The interfacial film between oil and water can then quickly be destabilized due to less viscous interfaces observed with certain ions to promote drop-drop coalescence and easy mobilization of released oil droplets. This coalescence process is sequential and it would continue until the formation of small oil bank. This is the first study that showed added importance of fluid-fluid interactions in SmartWater flood by using direct measurements on individual water ions at crude oil-water interface. In addition, a new oil recovery mechanism was proposed by combining both the interactions occurring at fluid-fluid and rock-fluids interfaces. The new fundamental knowledge gained in this study will provide an important guidance on how to synergize water ion interactions at fluid-fluid interfaces with those at rock-fluids interfaces to optimize oil recovery from SmartWater flood.
- Europe (1.00)
- North America > United States > Texas (0.46)
- Asia > Middle East > Saudi Arabia (0.28)
- Geology > Rock Type > Sedimentary Rock (0.47)
- Geology > Geological Subdiscipline (0.46)
- Geology > Mineral > Sulfate (0.37)
Abstract Low-salinity waterflooding has been portrayed as an effective enhanced-oil recovery technology. Despite compelling laboratory and field evidence of its potential, the underlying mechanisms still remain controversial. In this study, the enhanced-oil recovery mechanisms are investigated considering a distinct interfacial effect, i.e. water-crude oil interfacial viscoelasticity, through analysis of capillary hysteresis. An experimental setup with an oil-wet and a water-wet media on each end face of the core sample was utilized to capture capillary and rock electrical properties hysteresis. Moreover, new improvements over the traditional quasi-static porous plate method were implemented to accelerate measurements. Two experiments were conducted on Minnelusa formation rock samples and TC crude oil, at low temperature (30 °C) and without any significant aging as to minimize wettability alteration. Two core plugs were flooded with high-salinity and low-salinity brines, separately. It is found that the dynamic-static method with a ceramic disk, i.e. a combination of continuous injection in drainage and stepwise quasi-static method in imbibition on short 1" long core samples, allows one to capture the correct envelopes of the capillary pressure curves and save ~ 30% of the total time; a thin membrane is anticipated to save ~90% with respect to traditional quasi-static porous plate method. The capillary hysteresis experiments at low temperature prove that low-salinity brine is able to suppress capillary hysteresis. This is attributed to the formation of a more visco-elastic brine-crude oil interface upon exposure to low-salinity brine, leading to a more continuous oil phase. In addition, we show that wettability plays an essential role on electrical resistivity and the more oil-wet, the more hysteresis occurs, namely that resistivity values in imbibition are higher than those in drainage. The findings in this paper demonstrate that low-salinity waterflooding can still increase oil recovery even in the absence of wettability alteration.