Browsing by Subject "Spontaneous imbibition"
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Item Enhanced oil recovery in fractured vuggy carbonates(2014-05) Chen, Peila; Mohanty, Kishore Kumar; Pope, Gary A.; Balhoff, Matthew T.; Delshad, Mojdeh; Arbogast, Todd J.Naturally fractured carbonates contribute substantially to global oil reserves. Waterflood and gas-oil gravity drainage (GOGD) recover oil from the fractured oil-wet carbonates, with limited success due to poor sweep and very low recovery factors. Surfactant flooding has shown a great potential to enhance oil recovery in the oil-wet carbonates by reducing interfacial tension and/or altering wettability. Carbonates are characterized by the wide pore-size distributions. Surfactant EOR cannot be successfully implemented in a fractured, oil-wet, carbonate reservoir unless the reservoir is fully characterized and all of the mechanisms involved in oil recovery are fully understood. NMR T₂ measurement, mercury injection capillary pressure test (MICP), thin-section imaging, and computerized tomography (CT) scanning were conducted in the characterization of vuggy dolomite cores from the field. Both thin section and CT images reveal that the touching vugs and separate vugs co-exist in the core samples. Although the vuggy porosity is estimated to be 85%, the matrix controls the permeability of the core because of poor vug connectivity. MICP and NMR T₂ measurements show multimodal pore-throat and pore-body size distributions. Reconstructed 3D CT porosity maps indicate that the vugs in the field dolomite are large and randomly distributed, while the vugs in the Silurian dolomite are small and densely populated. A single-phase tracer test performed under CT scanner reveals a large porosity variation and the preferential flow paths within the field dolomite core. The mercury withdrawal test and NMR T₂ measurement have indicated that snap-off retains oil in the vugs due to the large aspect ratio pores and the large length-scale of the oil blobs. The imbibition oil recovery from the initially oil-wet field dolomite core is 20% lower (in OOIP) than that from the Silurian dolomite core, mainly because of an unfavorable pore structure in the field dolomite core. A few surfactants were selected as promising candidates for wettability alteration because they possess aqueous stability in hard brine at elevated temperatures and reduce contact angles. The divalent cations in the hard brine significantly suppress the anionic surfactant-mediated wettability alteration. The removal of Ca²⁺, and then Mg²⁺ from the hard brine progressively promotes anionic surfactant-assisted wettability alteration, evidenced by decreasing contact angles. The addition of sufficient amount of divalent ion scavengers, including chelating agents (e.g. EDTA.4Na) and scale inhibitors (e.g. Sodium Polyacrylate) in the hard brine, rescues the anionic surfactant-mediated wettability alteration. We propose that the scavenger reduces the concentration of free divalent cations, and promotes the release of the surfactant monomers, which favors wettability alteration through the surfactant adsorption mechanism. The scavenger- triggered mineral dissolution only weakly contributes to the imbibition oil recovery. Experiments and simulation studies consistently showed the synergy between wettability alteration and IFT reduction in a surfactant-assisted gravity-driven process. The residual oil saturation after gravity drainage is approximately 10~20% higher than that by gravity-driven imbibition if the two processes have the same trapping number N[subscript T], which implies that wettability alteration contributes to oil recovery from the oil-wet carbonates. A critical capillary number was found in the capillary desaturation curve plotted for the spontaneous imbibition tests, not for gravity drainage tests. In a UTCHEM model, wettability alteration is represented by the changes in P[subscript c], k[subscript r] and CDC. The simulation successfully history-matched and also predicted the incremental oil recovery by the surfactant formulations. The sensitivity study carried out in UTCHEM simulation shows the strong effects of fluid density, capillary pressure and vuggy pore structures on oil recovery. Three current available oil recovery prediction models (Hagoort, 1980; Aronofsky, 1958; Gupta and Civan, 1994) were tested against imbibition experiments. Two new analytical models were developed in this work, which significantly improved the quality of matching with experimental oil recovery. The matrix-fracture transfer functions, derived from the analytical oil recovery models, can be implemented in a dual-porosity simulator, providing more accurate numerical simulations of oil production in the fractured reservoirs. Lastly, we investigated the feasibility of using single well tracer test (SWTT) in the fractured reservoirs to determine the ROS or connate water saturation. The fractures studied are mainly small-scale fractures. The effects of fracture and its orientation on SWTTs were studied in four Berea cores with a single fracture in each core, orientated as 90°, 60°, 30°, and 0° against dominant flow direction. A simple Cartesian grid without dual porosity in UTCHEM simulator is adequate to interpret the experimental data. A synthetic field-scale SWTT is not sensitive to the presence of moderate degrees of small-scale fractures. The sensitivity study of fluid drift, representing flow irreversibility in a fractured reservoir, reveals the existence of a critical drift velocity, below which the tracer breakthrough curves (BTCs) are interpretable.Item Evaluation and design of surfactant formulations for wettability alteration(2020-05-14) Das, Soumik; Bonnecaze, R. T. (Roger T.); Nguyen, Quoc P.; Rochelle, Gary; Lynd, Nathaniel; Acevedo, ClaribelOnly about 35% of oil is recovered from carbonate reservoirs through primary and secondary flooding because of oil wet surfaces and unfavorable capillary pressures. Surfactants, with their dual hydrophobic and hydrophilic nature have been known to improve oil recovery significantly by lowering oil-water interfacial tension and by altering wettability of surfaces. However, the process of selecting an efficient surfactant for wettability alteration is dependent on several factors, including mineral type, porosity, temperature, salinity, nature of adsorbed oil, molecular structure and surfactant adsorption. Core-flood experiments usually used for evaluating surfactants tend to be time-consuming and provide very little information on the actual mechanism of surfactant action. A fast evaluation scheme is hence required to measure surfactant performances corresponding to the above mentioned parameters. The current work focusses on macro and molecular scale analysis of surfactants to understand relevant structure-property relationships and mechanism of wettability alteration. Surfactants are first evaluated and screened through a series of phase behavior, contact angle and oil-film experiments. The experimental observations have been used to correlate parameters like molecular structure, temperature and brine salinity to macroscopic properties like wettability alteration, adsorption and capillary driving force. Oil-film experiments have been used to understand the surfactant-aided wettability alteration. The role of surfactant adsorption in wettability alteration is investigated by static adsorption experiments. Adsorption isotherms are measured for different surfactant hydrophilicities at different temperatures and surfactant cloud point is used to develop a thermodynamic model explaining the universal surfactant behavior. Along with experiments, molecular dynamics simulations are also performed to understand the mechanism of aggregative adsorption of the nonionic surfactants. To address the issue of high temperature, high salinity applications, mixed surfactant formulations of nonionic surfactants and anionic hydrotropes are developed. Detailed investigations are performed to understand the role of hydrotrope structure, concentration and temperature on the mechanism of aqueous stabilization and adsorption and their effect on wettability alteration. Overall, the current work first establishes a macro and molecular-scale understanding of the phenomenon of surfactant-assisted wettability alteration and associated structure-property relationships. While shorter surfactant hydrophilic units and high temperatures are found to exhibit better wettability alteration, in fact it is proximity to surfactant cloud point which is the determining thermodynamic descriptor. Improved wettability alteration is correlated with surfactant adsorption which occurs in an aggregative manner. It also means there is a tradeoff between surfactant adsorption and wettability alteration. Using this knowledge, surfactant formulations are developed to observe and predict enhanced oil recoveries from representative porous media.Item Gravimetric measurement of spontaneous imbibition of water in organic-rich shales(2013-12) Gilmore, Evan Daniel; Sharma, Mukul M.; Chenevert, Martin EOrganic-rich shales in the last decade have become a focus of the oil and gas industry, and currently are the primary source of oil and gas production from Unconventional resources. These resources will be in need of a method of enhanced recovery to maximize lifetime production from each well. Spontaneous imbibition, or the adsorption of a fluid into a porous media due to capillary forces and consequent displacement of non-wetting fluids is a good potential enhanced recovery method. Measuring the amount of spontaneous imbibition in an organic-rich shale is complicated by several challenges compared to traditional oil reservoir rocks, such as the ultra-low permeability and the high clay content. This clay content can often lead to swelling, which can affect imbibition measurements. In this study, a new gravimetric method for measuring spontaneous imbibition is developed that can measure the rate, and volume of spontaneous imbibition as well as the degree of shale swelling. Two organic-rich shales, the Bakken and the Utica were examined and compared to establish the viability of the experimental method. The results of this work suggest that this method is a promising and viable method for measuring the volume and rate of spontaneous imbibition in organic-rich shale. The exposure of organic-rich shales to atmospheric conditions can significantly modify the properties of the shale through drying or hydration of the samples. All of the shales used in experiments in the following study were carefully maintained at their native state before exposure to the imbibition fluids. Additionally, the shale samples were exposed to several surfactant mixtures to measure the effect of these surfactants on the rate of imbibition.Item Low tension and wettability alteration EOR approaches for a high temperature high salinity carbonate reservoir(2021-04-30) Tibrewala, Yash Vishal; Mohanty, Kishore KumarCarbonate reservoirs account for more than half of the world’s oil reserves. Many carbonate reservoirs have low oil recovery due to their heterogeneity and oil-wetness. This research work focuses on developing chemical enhanced oil recovery methods for a reservoir with high temperature (100°C), high salinity (35000 ppm) and light oil (40° API). The work tested deployment of both the ultra-low interfacial tension method and the wettability alteration method to increase the oil recovery. The ultra-low interfacial tension formulation was found to incorporate three surfactants at 0.5 wt% and one co-solvent at 0.75 wt%. It also used a polymer at 5000 ppm to control the mobility and increase the sweep efficiency. The solution was found by conducting phase behavior experiments on a range of surfactants and was tested in two sand packs made of the reservoir rock. The first flood (143mD) employed a salinity gradient and led to an oil recovery of 99.9%. The second flood (202mD) was conducted at constant salinity and led to an oil recovery of 98.1%. A single surfactant solution was found for the wettability alteration method. This process does not use any polymer. The solution was arrived at by conducting contact angle and spontaneous imbibition experiments. During the spontaneous imbibition experiment, the surfactant recovered 33% of total oil in place compared to only 10% recovered by the control sample (sea water). The surfactant was tested in a secondary core flood (0.17 mD) and led to an oil recovery of 54.3%. Additionally, it was tested in a tertiary core flood (2.87mD) and managed to increase the oil recovery from 51.9% during water flood to 69.2% after surfactant flood. Both methods have been successful in demonstrating an increase in oil recovery during a flood. The ultra-low interfacial tension approach could not be tested in reservoir core samples due to their low permeability and lack of polymer transport. While the wettability alteration approach has demonstrated a significantly less recovery than the ultra-low interfacial tension approach, it is expected to be much more cost effective due to the less amount of surfactant used and no use of polymersItem Modeling of fluid imbibition and chemical tracer transport in porous media for oil recovery applications(2023-08-11) Velasco Lozano, Moises; Balhoff, Matthew; Pope, Gary; Delshad, Mojdeh; Pyrcz, Michael; Javadpour, FarzamModeling of fluid and solute transport in porous media is fundamental to describing driving mechanisms of recovery methods before their field application, however, conventional simulations and experiments demand time and expertise. Therefore, this research work presents novel real-time solutions for spontaneous imbibition (SI) and chemical tracer transport in porous media for two-phase flow. Although imbibition tests are critical to evaluating the displacement of oil by water and chemical solutions, the existing models fail to properly estimate the entire imbibition process. Therefore, a new semi-analytical solution for SI, valid during the infinite-acting and boundary-dominated regimes, was derived. The solution was validated with experimental data for different flow geometries under diverse flow conditions and capillary pressure functions, obtaining differences of less than 5%. Additionally, a numerical model is presented to examine SI in cores with a discrete fracture by including a new transfer function in the fracture equation to account for the fluid exchange at the matrix-fracture boundary. As a result, the flow model is reduced to a one-dimensional equation that is numerically solved using finite differences, leading to the accurate and rapid modeling of fluid displacement, obtaining results comparable to two-dimensional simulations. In addition, first-ever solutions are presented for the modeling of chemical tracer transport in two-phase flow in capillary- and advective-dominated systems at core scale, accounting for hydrodynamic dispersion, partitioning, and adsorption. These novel solutions are derived using Laplace transform and a series of transformation variables that simplify the highly nonlinear advection-dispersion equation, resulting in real-time analysis with simple mathematical expressions that do not require complex numerical calculations or inversion methods. Finally, a convolutional neural network is developed to estimate residual oil saturation based on the generation of partitioning tracer responses as a function of ideal tracer profiles, where the results obtained demonstrate that this machine learning method serves as a complementary tool to significantly reduce the number of reservoir simulations. Thus, the models described in this work are innovative approaches that facilitate the analysis of fluid and tracer dynamics at core and field scales for oil recovery and subsurface applications.Item Surfactant-aided wettability alteration in low-temperature low-salinity carbonate reservoirs(2021-08-02) Almansouri, Mohammed A.; Mohanty, Kishore KumarCarbonate reservoirs tend to be oil-wet/mixed-wet and heterogeneous, which makes wettability alteration a key method for increasing oil recovery. Carbonate reservoirs are often fractured, especially with increased dolomitization. Changing wettability to a water-wet state aids water imbibition into the matrix, thereby sweeping bypassed oil. The objective of this study is to improve oil recovery in low-temperature dolomite reservoirs using low-salinity surfactant solutions. This work evaluates the potential of using surfactants in a low-temperature carbonate formation with a formation brine salinity of 10,887 ppm. The reservoir has a high dolomite concentration with a high density of fractures and an intermediate to oil-wet wettability. Brine composition was optimized using zeta potential and contact angle measurements. Surfactants were screened based on their aqueous stability under reservoir conditions and were further screened using contact angle experiments. Experiments of spontaneous imbibition upon exposure to surfactants on carbonate rocks have been conducted using various surfactant types and concentrations. Also, a coreflood was completed to evaluate recovery due to wettability alteration. Additionally, changing water salinity was performed to assess the impact on the wettability of carbonate surfaces. The effects of surfactant formulations and observations are discussed. Optimized surfactant formulations were found to increase oil recovery to up to 10.4% from conventional waterflooding