One of the unanswered issues with steam applications is the wettability state during the process. Removal of polar groups from the rock surface with increasing temperature improves water wettability; however, other factors, including phase change, play a reverse role on it. In other words, hot water or steam will show different wettability characteristics, eventually affecting the recovery. On the other hand, wettability can be altered using steam additives. The mechanism of these phenomena is not yet clear. The objective of this work is to quantitatively evaluate the steam-induced wettability alteration in different rock systems and analyze the mechanism of wettability change caused by the change of the phase of water and chemical additives.
Heavy-oil from a field in Alberta (27,780 cP at 25°C) was used in contact angle measurements conducted on mica, calcite plates, and rock pieces obtained from a bitumen containing carbonate reservoir (Grosmont). All measurements were conducted at a temperature range up to 200°C using a high-temperature high-pressure IFT device. To obtain a comprehensive understanding of this process, different factors, including the phase of water, pressure, rock-type, and contact sequence were considered and studied separately.
Initially, the contact angles between oil and water were measured at different pressures to study the effect of pressure on wettability by maintaining water in the liquid phase. Secondly, the contact angle was measured in pure steam by keeping pressure lower than the saturation pressure. The influence of contacting sequence was investigated by reversing the sequence of generating steam and introducing oil during measurement. These measurements were repeated on different substrates. Different temperature resistant chemicals (surfactants and alkalis) were added to steam during contact angle to test their wettability alteration characteristics at different temperature and pressure conditions (steam or hot-water phases). The results showed that wettability of tested substrates is not sensitive to pressure as long as the phase has not been changed. The system, however, was observed to be more oil-wet in steam than in water at the same temperature, for example, in the case of calcite.
Analysis of the degree of the wettability alteration induced by steam (or hot-water) and temperature was helpful to further understand the interfacial properties of steam/bitumen/rock system and useful in the recovery performance estimation of steam injection process in carbonate and sand reservoirs.
Electromagnetic (EM) heating has been proposed to recover heavy oil due to its great environmental friendliness. Previous studies focused on investigating the feasibility and enhancing the oil recovery of such non-aqueous method. However, the effect of EM heating on the variations of formation rock properties is still elusive. Detailed experiments/measurements are required to understand the effect of EM heating on changing the petrophysical properties of formation rocks.
A commercial microwave oven is used to conduct the EM heating experiments. Different types of formation rocks (shale, Berea-sandstone, tight sandstone, and Indiana-carbonate) are investigated. Various techniques, including scanning electron microscopy (SEM), energy dispersive X-ray (EDX), N2 adsorption/desorption, and X-Ray fluorescence (XRF), are used to characterize the properties of shale samples before/after experiments. The porosity and permeability measurement are performed to Berea sandstone, tight sandstone, and Indiana carbonate. An infrared thermometer is used to measure the samples’ surface temperatures. Furthermore, oven-heating experiments are conducted to distinguish the effects of conductive-heating and EM heating on the property changes of rock-samples.
Results show that different types of rocks exhibit different responses to EM heating; shale samples exhibit a higher temperature compared with sandstone and carbonate because of the better EM energy absorbance of clays and pyrite. The shale samples are crumbled into pieces or fractured after EM heating, while the sandstone and carbonate samples remain almost unchanged after EM heating. The SEM results reveal that EM heating causes tensile failure, shrinkage of clay, and release of volatile organic content to the shale sample. The N2 adsorption/desorption measurements demonstrate that the pore volume significantly increases due to clay shrinkage, while part of the pore can be blocked by the converted bituminous kerogen after EM heating. EM heating has almost no effect on Berea sandstone and Indiana carbonate due to the transparency of quartz and calcite to EM waves. However, the EM heating can fracture the tight sandstone that is saturated with water because of the rapid rise of pore pressure under EM heating.
This study focuses on the ability of complex colloidal solution to stabilize a heavy oil-brine Pickering emulsion by changing the activity at the interface between heavy oil and brine. After testing many different combinations of anionic and cationic surfactants and nano-particles, we formulated the best stability options and created oil-in-water Pickering emulsions stabilized by silica, a cationic surfactant [dodecyltrimethylammonium bromide (DTAB)], and an anionic surfactant [alcohol propoxy sulfate (Alfoterra S23-7S-90)]. Then, various core flooding experiments were conducted in order to demonstrate the practical ability of the created emulsion system and observe its capacity to enhance oil recovery. Rate-dependency flooding tests were also conducted to determine the optimal flow rate required for heavy oil production through emulsification for different permeability media. Ultimately, slim tube sandpack flooding experiment at the optimal rate was conducted to confirm in-situ emulsion generation and to support the potential use of the chemical combination in the heavy oil industry.
Phase behavior of fluids at capillary conditions differs from that in bulk media. Therefore, understanding the thermodynamics of solvents in confined media is essential for modeling thermal EOR applications. The Thomson equation states that pore sizes have a control on boiling points of liquids in capillary channels. As pore spaces become smaller, boiling points become lower than normal boiling temperatures of the same liquids. The target of this paper is to inspect this phenomenon by physically measuring the boiling points of several solvents and compare them with the calculated boiling temperatures for different capillary structures. Furthermore, the feasibility and accuracy of the Thomson equation is investigated to check its applicability in heavy-oil recovery modelling. To do so, Hele-Shaw cells with several gap thicknesses (0.04, 0.45, 1.02, and 12 mm) are used to measure the boiling points of heptane, heptane-decane mixture, and naphtha. Experiments are repeated for the same solvents on homogeneous and heterogeneous micromodels to observe the phase behavior in a more realistic porous medium. Finally, the effect of surface wettability on boiling temperatures is examined in Hele-Shaw and micromodel experiments.
Solvent/thermal hybrid methods have been proposed recently to enhance heavy-oil recovery and to overcome the shortcomings that are encountered when either method is solely applied. One of the methods for this hybridization is to combine electromagnetic (EM) heating and solvent injection to facilitate heavy-oil production by gravity drainage. This approach has several advantages including reduced CO2 emissions, decreased water consumption, and appropriateness for water-hostile reservoirs. We are currently lacking any mathematical model for better understanding, designing, and optimizing this hybrid technique, which is partly attributed to this technique still being in its infancy.
We propose a semianalytical model to predict the oil-flow rate resulting from the combined EM heating and solvent-assisted gravity drainage. The model first calculates the temperature distribution within the EM-excited zone caused by the radiation-dominated EM heating. Using different attenuation coefficients within and beyond the vapor chamber, the model can properly describe the corresponding temperature responses in these regions. Next, an average temperature of the chamber edge contributed by EM heating is used to estimate the temperature-dependent properties, such as vapor/liquid equilibrium ratios (K-values), heavy-oil/solvent-mixture viscosity, and solvent diffusivity. Subsequently, a 1D diffusion equation is used to calculate the solvent-concentration distribution ahead of the chamber edge. Eventually, the oil-flow rate is evaluated with the calculated temperature and solvent distributions ahead of the chamber edge. The proposed model is validated against the experimental results obtained in our previous study, and the predicted oil-flow rate agrees reasonably well with the experimental data.
The proposed model can efficiently predict the oil-flow rate of this hybrid process. We conduct sensitivity analyses to examine the effect of major influential factors on the performance of this hybrid technique, including EM heating powers, solvent types, solvent-injection pressures, and initial reservoir temperatures. The modeling results demonstrate that a higher EM heating power, a heavier solvent, and a higher solvent-injection pressure could accelerate the oil-recovery rate, but tend to lower the net present value (NPV) and increase the energy consumption. In summary, the newly proposed model provides an efficient tool to understand, design, and optimize the combined technique of EM heating and solvent-assisted gravity drainage.
Late cycles of cyclic steam stimulation (CSS) are characterized by a decreasing heavy-oil recovery and an increasing water cut. Nickel nanoparticles can be used to promote aquathermolysis reactions between water and heavy oil in steam-injection processes, thereby increasing the recovery factor (RF). In this paper, detailed investigations were performed to determine the optimal operational parameters and answers to the following questions:
CSS experiments were conducted between temperatures of 150 and 220°C. Steam generated under these temperatures was injected into sandpacks saturated with Mexican heavy oil. Powder-form nickel nanoparticle was introduced into this process to boost the oil production. In an attempt to obtain the optimal concentration, different concentrations were tested. Next, oil sands without any nanoparticle additives were first added into the cylinder. Then, only one-third of the sandpack was mixed with nickel nanoparticles near the injection port. Experiments were executed to study the effects of temperature, nickel concentrations, and nanoparticle-penetration depth on the ultimate oil recovery and produced oil/water ratios after each cycle. Produced-oil quality and emulsion formation were evaluated with gas-chromatography (GC) analysis, viscosity measurements, saturates/asphaltenes/resins/aromatics (SARA) tests, and microscopic analysis of the effluents.
Experimental results show that the best concentration of nickel nanoparticles, which gives the highest ultimate oil RF, is 0.20 wt% of initial oil in place (IOIP) under 220°C, whereas the nickel concentration of 0.05 wt% provides the highest RFs at the early stages. A lower temperature of 150°C provides a much-lower RF than 220°C, which is mainly because of a lower level of aquathermolysis reactions at 150°C. By analyzing the compositions of produced oil and gas samples with GC and SARA tests, we confirm that the major reaction mechanism during the aquathermolysis reaction is the breakage of the carbon/sulfur (C/S) bond; the nickel nanoparticles can act as catalyst for the aquathermolysis reaction; and the catalytic effect becomes less remarkable from cycle to cycle. One run of the experiment to test the effect of particle-penetration depth revealed that the nickel nanoparticles distributed near the injection port greatly contributed to the ultimate RF.
Huang, Hai (Xi'an Shiyou University and Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta) | Andy Li, Huazhou (University of Alberta) | Develi, Kayhan (Istanbul Technical University)
The fracture-surface characteristics (such as roughness and fractal dimensions) may greatly affect the proppant transport during hydraulic fracturing operation. Few researches have focused on investigating the proppant transport in vertical fracture with actual surface characteristics. As a continuation of our previous study (
Primary recovery of heavy-oil is remarkably low due to high viscosity and low energy by solution gas exsolution to drive the oil. Gas injection to improve foamy flow and also to dilute the oil in such reservoirs has been proposed as a secondary recovery method. However, because of the high costs of injected gases, efforts are needed to optimize the process by selection of proper gas type (or gas combinations) and suitable injection scheme. To achieve this goal, an experimental procedure was followed with rigorous analyses of the output. A 1.5 m long and 5 cm diameter sand-pack was first saturated with brine, which was replaced with dead oil. Then, gas solvents were injected to dead-oil containing core-holder until nearly reaching 500 psi followed by a two-day soaking period. Pressures all along the sand-pack were recorded with eight pressure transducers. Different combinations of various gas solvents (methane, CO2, and air) aiming to select the most competitive and economic formula were tested with a certain set of pressure depletion rates.
The physics of the foamy oil flow for different solvent mixtures and depletion conditions were analyzed using pressure profiles acquired, recorded oil/gas data with time, and gas chromatography and SARA analyses of the produced gas and oil. Three huff-n-puff cycles were applied. Compared with other light hydrocarbon solvents and carbon dioxide, air has its high advantage in terms of accessibility and lowered cost. Hence, attention was given to air that was mainly used to pressurize the system and increase oil viscosity due to oxidation process with an expectation of better foam quality when injected with other gases such as CO2 and methane. Methane (CH4) yielded the quickest response in terms of gas drive but, in the long run, CO2 was observed to be more effective technically. Air was observed to be effective if mixed with CO2 or methane from an economics point of view. To sum up the results, air Huff-n-Puff (HnP) followed by 2-cycles of CH4 HnP yielded 36.21% recovery, while air HnP followed by 2-cycles of CO2 HnP delivered 30.36% oil. When the gases are co-injected, air 50%-CO2 50% and air 50%-CH4 50% recovered 29.85% and 23.74% of total oil-in-place, respectively.
This paper reports the results of laboratory scale screening of different chemicals for their microeumlsion generation capabilities to be eventually recommended for non-thermal heavy oil recovery (chemical flooding). The study was performed through visualization of microemulsions generated using vials and microscopic images. The impact of salinities of brine on the emulsification was studied thoroughly in order to identify the synergy between the selected chemicals and the heavy oil. An alcohol propoxy sulfate surfactant from the Alfoterra series, Alfoterra S23-7S-90, a nonionic surfactant HORA-W10, gave good emulsion formation results at low salinity conditions (2.5 wt. %, 3.8 wt. %). Polysorbate-type nonionic surfactant Tween 20 gave good emulsion formation at high salinity conditions (6.35 wt. %, 7.6 wt.%). Their emulsion formation performance with a crude heavy oil of viscosity 4,812cP and 11.74 °API helped create an initial correlation of performance with the composition of crude oil and synthetic brine samples of various salinities. Attempts were also made to stabilize oil-in-water emulsions formed with Alfoterra S23-7S-90, HORA-W10, Tween 20 using nanofluids (metal oxides), sodium carbonate, and an anionic polyacrylamide-based polymer (PolyFlood MAX-165). Emulsions were visualized under the Axiostar plus transmitted-light microscope and their stability was studied in order to screen the most optimal chemical (or chemical combinations) available for low cost heavy oil recovery.
As stated by the classical Thomson equation, the pore scale thermodynamics of solvent is different from bulk conditions being critically controlled by capillary characteristics. This equation shows that the boiling points decrease remarkably as the pore size and interfacial tension become smaller. This paper investigates this phenomenon for hydrocarbon solvents experimentally and compares the results with the values obtained from the Thomson equation to test its applicability in modelling heavy-oil recovery by solvents under non-isothermal conditions. As an initial step, the boiling temperature of different single component solvents (heptane and decane) was measured by saturating Hele-Shaw type cells with variable apertures (ranging from 0.04 mm to 5 mm) and monitoring the boiling process. One experiment was run with a thickness of 12 mm to represent the bulk case. As the aperture (pore size) became smaller, the boiling point temperature decreased. For example, the measured boiling temperatures of heptane and decane were approximately 57.7°C and 107.4°C for the aperture values less than 0.15 mm, which were considerably lower than the "bulk" values (around 40%). In the next step, the same experiments were repeated using micromodels representing porous media. The micromodel (grain diameter of 0.15 mm and a pore throat of 0.075 mm) was designed with uniform properties (constant grain diameter and pore throat). By using the Thomson equation, the boiling points of the selected liquids were mathematically computed and compared with the experimental results from Hele-Shaw experiments.