Pore-scale imaging and analysis of low salinity waterflooding in a heterogeneous carbonate rock at reservoir conditions.
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ABSTRACT:
SUBMITTER: Selem AM
PROVIDER: S-EPMC8302661 | biostudies-literature |
REPOSITORIES: biostudies-literature
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Project description:Low salinity waterflooding has proven to accelerate oil production at core and field scales. Wettability alteration from a more oil-wetting to a more water-wetting condition has been established as one of the most notable effects of low salinity waterflooding. To induce the wettability alteration, low salinity water should be transported to come in contact with the oil-water interfaces. Transport under two-phase flow conditions can be highly influenced by fluids topology that creates connected pathways as well as dead-end regions. It is known that under two-phase flow conditions, the pore space filled by a fluid can be split into flowing (connected pathways) and stagnant (deadend) regions due to fluids topology. Transport in flowing regions is advection controlled and transport in stagnant regions is predominantly diffusion controlled. To understand the full picture of wettability alteration of a rock by injection of low salinity water, it is important to know i) how the injected low salinity water displaces and mixes with the high salinity water, ii) how continuous wettability alteration impacts the redistribution of two immiscible fluids and (ii) role of hydrodynamic transport and mixing between the low salinity water and the formation brine (high salinity water) in wettability alteration. To address these two issues, computational fluid dynamic simulations of coupled dynamic two-phase flow, hydrodynamic transport and wettability alteration in a 2D domain were carried out using the volume of fluid method. The numerical simulations show that when low salinity water was injected, the formation brine (high salinity water) was swept out from the flowing regions by advection. However, the formation brine residing in stagnant regions was diffused very slowly to the low salinity water. The presence of formation brine in stagnant regions created heterogeneous wettability conditions at the pore scale, which led to remarkable two-phase flow dynamics and internal redistribution of oil, which is referred to as the "pull-push" behaviour and has not been addressed before in the literature. Our simulation results imply that the presence of stagnant regions in the tertiary oil recovery impedes the potential of wettability alteration for additional oil recovery. Hence, it would be favorable to inject low salinity water from the beginning of waterflooding to avoid stagnant saturation. We also observed that oil ganglia size was reduced under tertiary mode of low salinity waterflooding compared to the high salinity waterflooding.
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Project description:Geologic storage of carbon dioxide (CO2) is considered a viable strategy for significantly reducing anthropogenic CO2 emissions into the atmosphere; however, understanding the flow mechanisms in various geological formations is essential for safe storage using this technique. This study presents, for the first time, a two-phase (CO2 and brine) flow visualization under reservoir conditions (10?MPa, 50?°C) for a highly heterogeneous conglomerate core obtained from a real CO2 storage site. Rock heterogeneity and the porosity variation characteristics were evaluated using X-ray computed tomography (CT). Multiphase flow tests with an in-situ imaging technology revealed three distinct CO2 saturation distributions (from homogeneous to non-uniform) dependent on compositional complexity. Dense discontinuity networks within clasts provided well-connected pathways for CO2 flow, potentially helping to reduce overpressure. Two flow tests, one under capillary-dominated conditions and the other in a transition regime between the capillary and viscous limits, indicated that greater injection rates (potential causes of reservoir overpressure) could be significantly reduced without substantially altering the total stored CO2 mass. Finally, the capillary storage capacity of the reservoir was calculated. Capacity ranged between 0.5 and 4.5%, depending on the initial CO2 saturation.
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Project description:Although thermal methods have been popular and successfully applied in heavy oil recovery, they are often found to be uneconomic or impractical. Therefore, alternative production protocols are being actively pursued and interesting options include water injection and polymer flooding. Indeed, such techniques have been successfully tested in recent laboratory investigations, where X-ray scans performed on homogeneous rock slabs during water flooding experiments have shown evidence of an interesting new phenomenon-post-breakthrough, highly dendritic water fingers have been observed to thicken and coalesce, forming braided water channels that improve sweep efficiency. However, these experimental studies involve displacement mechanisms that are still poorly understood, and so the optimization of this process for eventual field application is still somewhat problematic. Ideally, a combination of two-phase flow experiments and simulations should be put in place to help understand this process more fully. To this end, a fully dynamic network model is described and used to investigate finger thickening during water flooding of extra-heavy oils. The displacement physics has been implemented at the pore scale and this is followed by a successful benchmarking exercise of the numerical simulations against the groundbreaking micromodel experiments reported by Lenormand and co-workers in the 1980s. A range of slab-scale simulations has also been carried out and compared with the corresponding experimental observations. We show that the model is able to replicate finger architectures similar to those observed in the experiments and go on to reproduce and interpret, for the first time to our knowledge, finger thickening following water breakthrough. We note that this phenomenon has been observed here in homogeneous (i.e. un-fractured) media: the presence of fractures could be expected to exacerbate such fingering still further. Finally, we examine the impact of several system parameters, including core length, wettability and injection rate, on the extent and efficiency of the finger swelling phenomenon.
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Project description:Recently, utilization of surfactant for EOR purposes in carbonate petroleum reservoirs has received the attention of many researchers. Surfactants generally appear to improve oil production through wettability alteration and reduction of interfacial tension (IFT) between oil and water phases. Loss of surfactant due to adsorption process is considered as an unfavorable phenomenon in surfactant flooding while conducting an EOR operation. In this study, a new plant-derived surfactant, called Zyziphus Spina Christi (ZSC), with various magnitudes of salinity is employed. The adsorption behavior of this surfactant is investigated using the conductivity approach to explore the impacts of salt concentration on adsorption rate through batch tests. Core flooding tests are also conducted to study the effects of surfactant/salinity on recovery factor and relative permeability. Employing the kinetics and isotherm models, MgCl2 and KCl exhibit the greatest and lowest influence on the adsorption phenomenon, respectively. It is also concluded that the pseudo-second order kinetics and Freundlich isotherm model can satisfactorily describe the adsorption behavior of the surfactant onto carbonates in the presence of salt for the kinetics and equilibrium tests conditions, respectively. According to the production history, it is found that increasing surfactant concentration leads to a considerable increase in oil relative permeability and consequently improvement of oil recovery.
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Project description:We used X-ray micro-tomography to image the in situ wettability, the distribution of contact angles, at the pore scale in calcite cores from a producing hydrocarbon reservoir at subsurface conditions. The contact angle was measured at hundreds of thousands of points for three samples after twenty pore volumes of brine flooding.We found a wide range of contact angles with values both above and below 90°. The hypothesized cause of wettability alteration by an adsorbed organic layer on surfaces contacted by crude oil after primary drainage was observed with Scanning Electron Microscopy (SEM) and identified using Energy Dispersive X-ray (EDX) analysis. However, not all oil-filled pores were altered towards oil-wet conditions, which suggests that water in surface roughness, or in adjacent micro-porosity, can protect the surface from a strong wettability alteration. The lowest oil recovery was observed for the most oil-wet sample, where the oil remained connected in thin sheet-like layers in the narrower regions of the pore space. The highest recovery was seen for the sample with an average contact angle close to 90°, with an intermediate recovery in a more water-wet system, where the oil was trapped in ganglia in the larger regions of the pore space.
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Project description:A new class of surface active ionic liquids (SAIL) have been reported to be a greener alternative to the conventional surfactants in enhanced oil recovery (EOR). These SAILs work efficiently under harsh salinity conditions encountered in the reservoir thereby recovering more additional oil during the tertiary oil recovery process. Adsorption mechanism of SAILs on different rock surface is however, not yet reported in the literature. This article highlights adsorption mechanism of three cationic SAILs having different headgroups, viz., imidazolium, pyridinium, pyrrolidinium, on different rock surfaces (crushed natural carbonate rock and crushed sandstone rock). All the SAILs studied here however had the same tail length and same anion (Br-) attached to it. XRD and XPS characterization techniques reveal that the crushed natural carbonate rock contains a substantial amount of silica, thus rendering it a slight negative charge. Static adsorption tests show that the retention efficiency on the natural carbonate type of rock for all the SAILs was lower than the conventional cationic surfactant, CTAB. The adsorption data obtained thereby was examined using four different adsorption isotherm models (Langmuir, Freundlich, Redlich-Peterson, and Sips). Results suggest that Sips adsorption isotherm model can satisfactorily estimate the adsorption of all the surface active agents on the natural carbonate rock. Factors like mineralogical composition of rock surface, presence of divalents, temperature, and structure of surfactants strongly affect the amount of surfactant adsorbed on reservoir rock. In order to evaluate the simultaneous effect all these factors as well as their interdependence on the retention capability of the three SAILs, a design of experiments approach has been employed further in this study. Statistical analysis of the data obtained after performing the full factorial experiments reveal that at high salinity, imidazoluim based SAIL show minimal adsorption on crushed natural carbonate rock at higher temperature. In general, at a given ionic strength, with increasing temperature as the amount of divalent in the aqueous solution increases, the amount of SAIL adsorbed on both the rock types decreases. Electrostatic attraction is the basic mechanism in governing adsorption of SAILs on the two types of rock surfaces. Results presented in this work can be used for EOR schemes.
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Project description:An oilfield reservoir over long-term operation may have different petrophysical information, which has a significant impact on oilfield maintenance and finance. Successful oilfield enhanced oil recovery benefits a lot from identifying and analyzing the variations of the critical properties after long-term waterflooding treatments. Since the inspection wells drilled within different development periods contain the core samples that have the petrophysical information at that period, it is necessary to collect and test the samples from different periods to investigate the overall tendency of the petrophysical properties. The samples from four inspection wells, which were drilled in four stages since the very beginning of development, were subjected to in-laboratory core analysis methods to illustrate the variation of some critical parameters in the reservoir. The permeability and porosity variation are revealed clearly by the experimental results. The migration and dissolution of clay minerals play a crucial role in the variation of petrophysical information and pore structure. To quantify the variations above, we applied the multiple linear regression model into our investigation. The dependent variable and all of the predictors in the model come from the experimental results. The quantitative results show the closed correlation between different parameters in the formation. With the development stage moving forward, the weight coefficients for different predictors have multiple trends. The experimental and statistical approach provides a novel understanding of the reservoir properties with the effect of waterflooding treatment.
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Project description:This paper resolve the salinity-dependent interactions of polar components of crude oil at calcite-brine interface in atomic resolution. Molecular dynamics simulations carried out on the present study showed that ordered water monolayers develop immediate to a calcite substrate in contact with a saline solution. Carboxylic compounds, herein represented by benzoic acid (BA), penetrate into those hydration layers and directly linking to the calcite surface. Through a mechanism termed screening effect, development of hydrogen bonding between -COOH functional groups of BA and carbonate groups is inhibited by formation of a positively-charged Na+ layer over CaCO3 surface. Contrary to the common perception, a sodium-depleted solution potentially intensifies surface adsorption of polar hydrocarbons onto carbonate substrates; thus, shifting wetting characteristic to hydrophobic condition. In the context of enhanced oil recovery, an ion-engineered waterflooding would be more effective than injecting a solely diluted saltwater.
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Project description:Low salinity waterflooding (LSWF) and its variants also known as smart water or ion tuned water injection have emerged as promising enhanced oil recovery (EOR) methods. LSWF is a complex process controlled by several mechanisms and parameters involving oil, brine, and rock composition. The major mechanisms and processes controlling LSWF are still being debated in the literature. Thus, the establishment of an approach that relates these parameters to the final recovery factor (RFf) is vital. The main objective of this research work was to use a number of artificial intelligence models to develop robust predictive models based on experimental data and main parameters controlling the LSWF determined through sensitivity analysis and feature selection. The parameters include properties of oil, rock, injected brine, and connate water. Different operational parameters were considered to increase the model accuracy as well. After collecting the relevant data from 99 experimental studies reported in the literature, the database underwent a comprehensive and rigorous data preprocessing stage, which included removal of duplicates and low-variance features, missing value imputation, collinearity assessment, data characteristic assessment, outlier removal, feature selection, data splitting (80-20 rule was applied), and data scaling. Then, a number of methods such as linear regression (LR), multilayer perceptron (MLP), support vector machine (SVM), and committee machine intelligent system (CMIS) were used to link 1316 data samples assembled in this research work. Based on the obtained results, the CMIS model was proven to produce superior results compared to its counterparts such that the root mean squared rrror (RMSE) values for both training and testing data are 4.622 and 7.757, respectively. Based on the feature importance results, the presence of Ca2+ in the connate water, Na+ in the injected brine, core porosity, and total acid number of the crude oil are detected as the parameters with the highest impact on the RFf. The CMIS model proposed here can be applied with a high degree of confidence to predict the performance of LSWF in sandstone reservoirs. The database assembled for the purpose of this research work is so far the largest and most comprehensive of its kind, and it can be used to further delineate mechanisms behind LSWF and optimization of this EOR process in sandstone reservoirs.
| S-EPMC8638312 | biostudies-literature
Project description:Innovative solutions have been designed to meet the global demand for energy and environmental sustainability, such as enhanced hydrocarbon recovery and geo-sequestration of CO2. These processes involve the movement of immiscible fluids through permeable rocks, which is affected by the interfacial properties of rocks at the pore scale. Overcoming major challenges in these processes relies on a deeper understanding about the fundamental factors that control the rock wettability. In particular, the efficiency of oil recovery strategies depends largely on the 3D wetting pattern of reservoir rocks, which is in turn affected by the adsorption and deposition of 'contaminant' molecules on the pores' surface. Here, we combined high-resolution neutron tomography (NT) and synchrotron X-ray tomography (XRT) to probe the previously unobserved 3D distribution of molecular and mineralogical heterogeneity of oil reservoir rocks at the pore scale. Retrieving the distribution of neutron attenuation coefficients by Monte Carlo simulations, 3D molecular chemical mappings with micrometer dimensions could be provided. This approach allows us to identify co-localization of mineral phases with chemically distinct hydrogen-containing molecules, providing a solid foundation for the understanding of the interfacial phenomena involved in multiphase fluid flow in permeable media.
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