Thesis (M. Sc.)--University of Alberta, 2009. / Title from pdf file main screen (viewed on July 27, 2009). "A thesis submitted to the Faculty of Graduate Studies and Research in partial fulfillment of the requirements for the degree of Master of Science in Petroleum Engineering, Department of Civil and Environmental Engineering, University of Alberta." Includes bibliographical references.

acase@tulane.edu / The objective of this research is to study the surface/interfacial phenomena via video-microscopic observation and quantification inside a micro-channel or microcapillary, which can mimic the operating conditions of practical problems, such as ink-jet, lubricant oil neutralization and enhanced oil recovery. In the second chapter, a micropipette-in-microcapillary method is described for the surface tension measurement at high temperatures, which mimics the dimension and working environment of ink-jet print head. Temperature control within the confined space of a capillary was achieved by coating the outer surface of the housing microcapillary with an electrically conductive, transparent, tin-doped indium oxide (ITO) thin film as a heating jacket. The precision of this technique was discussed according to the comparisons of our results with published reference data for water, n-hexadecane, and n-decane at both room and elevated temperatures. Traditionally, the neutralization of sulfuric acid by engine oils has been the major focus, however, due to the introduce of biofuel or ethanol the acetic acid has become an important concern. In the third chapter, based on micropipette-in-square-channel video-microscopy setup, the neutralization reaction mechanism and reaction kinetics of acetic acid by fully formulated lubricant oil is discussed. It was found that the neutralization exists simultaneously on the oil-acid-interface and bulk-oil phase during the droplet shrinkage. Besides, FTIR and NMR analysis show the neutralization of acetic acid as an instantaneous process, and almost all of the dissolved acetic acid in the bulk is eventually neutralized. Due to the minor role of acetic acid dissolution compared to the interfacial reaction, an interface-reaction-rate-controlled kinetic mechanism is proposed as approximation to describe the neutralization process at different conditions. When glacial and diluted acetic acid droplets were neutralized in fully formulated lubricant oil, the experimentally measured shrinking radius agreed very well with the mathematical model. According to Arrhenius equation, the activation energy of neutralization reaction was determined to be constant and its range (Ea>21 kJ/mol) further validated the assumption of interface-controlled reaction kinetics. In the final chapter, an oil-soluble surfactant prepared by Eni S.p.A. was studied to enhance crude oil mobilization in cryolite-packed miniature bed, which provided a transparent porous media at the microscopic level. When the porous media was imbued with crude oil, the presence of the surfactant in the oil phase was able to improve the mobilization performance of crude oil by flushing. In order to deliver the oil-soluble surfactant and apply it to the removal of crude from porous media, an SDS solution was used to solubilize the surfactant, and the formation of SDS/Eni-Surfactant micellar solution was confirmed by Cryo-SEM images. Using the prepared micellar solutions in oil-removal tests on the packed bed, a very high effectiveness was demonstrated by image binarization, thus confirming the possibility to deliver liposoluble surfactants to the porous-media-trapped crude oil by means of hydrosoluble carriers. / 1 / Yufei Duan

archives@tulane.edu / 1 / Olakunle Francis Ojo

Compositional reservoir simulation studies were performed to investigate the effect of uncertain reservoir parameters, flood design variables, and economic factors on coupled CO₂ sequestration and EOR projects. Typical sandstone and carbonate reservoir properties were used to build generic reservoir models. A large number of simulations were needed to quantify the impact of all these factors and their corresponding uncertainties taking into account various combinations of the factors. The design of experiment method along with response surface methodology and Monte-Carlo simulations were utilized to maximize the information gained from each uncertainty analysis. The two objective functions were project profit in the form of $/bbl of oil produced and sequestered amount of CO₂ in the reservoir. The optimized values for all objective functions predicted by design of experiment and the response surface method were found to be close to the values obtained by the simulation study, but with only a small fraction of the computational time. After the statistical analysis of the simulation results, the most to least influential factors for maximizing both profit and amount of stored CO₂ are the produced gas oil ratio constraint, production and injection well types, and well spacing. For WAG injection scenarios, the Dykstra-Parsons coefficient and combinations of WAG ratio and slug size are important parameters. Also for a CO₂ flood, no significant reduction of profit occurred when only the storage of CO₂ was maximized. In terms of the economic parameters, it was demonstrated that the oil price dominates the CO₂ EOR and storage. This study showed that sandstone reservoirs have higher probability of need for CO₂i ncentives. In addition, higher CO₂ credit is needed for WAG injection scenarios than continuous CO₂ injection. As the second part of this study, scaling groups for miscible CO₂ flooding in a three-dimensional oil reservoir were derived using inspectional analysis with special emphasis on the equations related to phase behavior. Some of these scaling groups were used to develop a new MMP correlation. This correlation was compared with published correlations using a wide range of reservoir fluids and found to give more accurate predictions of the MMP. / text

Current oil production technologies recover only about one‐third to one‐half of the oil originally present in an oil reservoir. Given current oil prices, even a modest increase in oil recovery efficiency is fiscally attractive. One novel approach to increase oil recovery efficiency is a process called microbial enhanced oil recovery (MEOR), where microorganisms are either used as a clogging agent to redirect flow or to produce biosurfactant that reduces interfacial tension. This dissertation aims to understand the MEOR pore‐scale mechanisms relevant to oil recovery by taking a two‐fold approach where transparent 2‐dimensional micromodel experiments imaged with stereo microscopy and 3‐dimensional column experiments imaged with x‐ray computed microtomography (CMT) are utilized. Micromodel experiments allow for direct visualization of the biological phase (i.e. biofilm), however, only 2‐dimensional information is provided. Conversely, CMT experiments provide 3‐dimensional pore‐scale information, but lack the ability to image the biological phase. With this two‐fold approach, it is possible to distinguish multiple fluid interfaces, quantify fluid phase saturations, measure oil blob size distributions, and visualize the biological phase. Furthermore, a method to measure interfacial curvature from 3‐dimensional images is developed, providing researchers a new perspective from which to study multiphase flow experiments. Overall, the presented research utilizes pore‐scale imaging techniques to study the interfacial interactions occurring during MEOR in an effort to better explain the physics, and thus, increase the efficacy of MEOR. / Graduation date: 2012

Thesis (M.S.)--University of Wyoming, 2007. / Title from PDF title page (viewed on July 26, 2010). Includes bibliographical references (p. 93-96).

Alkali-Surfactant-Polymer (ASP) or Surfactant-Polymer (SP) flooding are attractive chemical enhanced oil recovery (EOR) methods. However, some reservoir conditions are not favorable for the use of polymers or their use would not be economically attractive due to low permeability, high salinity, or some other unfavorable factors. In such conditions, gas can be an alternative to polymer for improving displacement efficiency in chemical-EOR processes. The co-injection or alternate injection of gas and chemical slug results in the formation of foam. Foam reduces the relative permeability of injected chemical solutions that form microemulsion at ultra-low interfacial tension (IFT) conditions and generates sufficient viscous pressure gradient to drive the foamed chemical slug. We have named this technique of foam assisted enhanced oil recovery as Alkali/Surfactant/Gas (ASG) process. The concept of ASG flooding as an enhanced oil recovery technique is relatively new, with very little experimental and theoretical work available on the subject. This dissertation presents a systematic study of ASG process and its potential as an EOR method. We performed a series of high performance surfactant-gas tertiary recovery corefloods on different core samples, under different rock, fluid, and process conditions. In each coreflood, foamed chemical slug was chased by foamed chemical drive. The level of mobility control in corefloods was evaluated on the basis of pressure, oil recovery, and effluent data. Several promising surfactants, with dual properties of foaming and emulsification, were identified and used in the coreflood experiments. We observed a strong synergic effect of foam and ultra-low IFT conditions on oil recovery in ASG corefloods. Oil recoveries in ASG corefloods compared reasonably well with oil recoveries in ASP corefloods, when both were conducted under similar conditions. We found that the negative salinity gradient concept, generally applied to chemical floods, compliments ASG process by increasing foam strength in displacing fluids (slug and drive). A characteristic increase in foam strength was observed, in nearly all ASG corefloods conducted in this study, as the salinity first changed from Type II(+) to Type III environment and then from Type III to Type II(-) environment. We performed foaming and gas-microemulsion flow experiments to study foam stability in different microemulsion environments encountered in chemical flooding. Results showed that foam in oil/water microemulsion (Type II(-)) is the most stable, followed by foam in Type III microemulsion. Foam stability is extremely poor (or non-existent) in water/oil microemulsion (Type II (+)). We investigated the effects of permeability, gas and liquid injection rates (injection foam quality), chemical slug size, and surfactant type on ASG process. The level of mobility control in ASG process increased with the increase in permeability; high permeability ASG corefloods resulting in higher oil recovery due to stronger foam propagation than low permeability corefloods. The displacement efficiency was found to decrease with the increase in injection foam quality. We studied the effect of pressure on ASG process by conducting corefloods at an elevated pressure of 400 psi. Pressure affects ASG process by influencing factors that control foam stability, surfactant phase behavior, and rock-fluid interactions. High solubility of carbon dioxide (CO₂) in the aqueous phase and accompanying alkali consumption by carbonic acid, which is formed when dissolved CO₂ reacts with water, reduces the displacement efficiency of the process. Due to their low solubility and less reactivity in aqueous phase, Nitrogen (N₂) forms stronger foam than CO₂. Finally, we implemented a simple model for foam flow in low-IFT microemulsion environment. The model takes into account the effect of solubilized oil on gas mobility in the presence of foam in low-IFT microemulsion environment. / text

Foam has been used as a mobility control technique in CO₂ flooding to improve volumetric sweep efficiency. Stabilizing CO₂ foam with nanoparticle instead of surfactant has some notable advantages. Nanoparticle-stabilized foam is very stable because a large adsorption energy is required to bring nanoparticles to the bubble interfaces. As a solid, nanoparticle can potentially withstand the high temperature in the reservoir, providing a robust foam stability for an extended period of time. The ability of nanoparticles to generate foam only above a threshold shear rate is promising as foam can be engineered to form only in the high permeability zone. These nanoparticles are hundreds of times smaller than pore throats and thus can travel in the reservoir without plugging the pore throats. Surface-modified silica nanoparticle was found to stabilize CO₂ -in-water foam at temperature up to 80 ˚C and salinity as high as 7.2 wt%. The foam was generated through the co-injection of aqueous nanoparticle dispersion and CO₂ into consolidated rock cores, primarily sandstones, with and without an induced fracture in the core. A critical shear rate for foam generation was found to exist in both matrix and fracture, however, this critical rate varied with the experiment conditions. The effects of experimental parameters on the critical shear rate and foam apparent viscosity were also investigated. Additionally, the flow distribution calculation in fractured sandstone cores revealed a diversion of flow from fracture toward matrix once foam was generated, suggesting conformance control potential in fractured reservoirs. In order to study foam rheology, high-permeability beadpack was installed upstream of the core to serve as a foam generator. This allows the foam mobility to be measured solely while being transported through the core, without the complicating effect of transient foam generation in the core. The injection of the pre-generated foam into the core at residual oil condition was found to reduce the residual oil saturation to the same level as CO₂ flood, however, with the advantage of mobility control. The 'coalescence-regeneration' mechanism of foam transport in porous media possibly allowed the foam's CO₂ to contact and mobilize the residual oil. The injection of the foam slug followed by a slug of only CO₂ was also tested, showing similar viscosification as the continuous foam injection, however, required less nanoparticles. / text

The study of multiphase flow in porous media is highly relevant to many problems of great scientific importance, such as CO2 storage and enhanced oil recovery. Even though significant progress has been made in these areas, many challenges still remain. For instance, the leakage of stored CO2 may occur due to the capillary trapping failure of cap rock. Approximately 70% of oil cannot be easily recovered from underground, because the oil is held in tight porous rocks. Although CO2 storage and enhanced oil recovery are engineering processes at a geological scale, they are predominantly controlled by the transport and displacement of CO2 and reservoir fluids in aquifers and reservoirs, which are further controlled by wetting and fluid properties at pore scale. This work focuses on experimental investigations of pore-scale wetting and displacement of fluids and CO2 in porous core samples. Pore wetting, which has been measured based on contact angle, is a principal control on multiphase flow through porous media. However, contact angle measurement on other than flat surfaces still remains a challenge. In order to indicate the wetting in a small pore, a new pore contact angle measurement technique is developed in this study to directly measure the contact angles of fluids and CO2 in micron-sized pores. The equilibrium and dynamic contact angles of various liquids are directly measured in single glass capillaries, by studying the effects of surface tension, viscosity and chemical structure. The pore contact angles are compared with the contact angles on a planar substrate. The pore contact angle of a confined liquid in a glass capillary differs from the contact angle measured on a flat glass surface in an open space. Surface tension is not the only dominant factor affecting contact angle. The static contact angle in a glass pore also varies with liquid chemical structure. Viscosity and surface tension can significantly affect the dynamic pore contact angle. A new empirical correlation is developed based on our experimental data to describe dynamic pore wetting. The CO2-fluid contact angle in porous media is an important factor affecting the feasibility of long-term permanent CO2 storage. It determines CO2 flow and distribution in reservoirs or aquifers, and thus ultimately finally the storage capacity. CO2-fluid contact angles were measured in small water-wet pores and oil-wet pores, investigating the effect of CO2 phase (gas/liquid/supercritical). The CO2 phase significantly affects the CO2-fluid contact angle in an oil-wet pore. Supercritical CO2-fluid contact angles are larger than gas CO2-fluid contact angles, but are smaller than liquid CO2-fluid contact angles. However, this significant CO2 phase effect on contact angle was not observed in a water-wet pore. Another key issue considered in this study is two-phase flow displacement in porous media. This strongly relates to the important macroscopic parameters for multiphase flow transport in porous media, such as capillary pressure and relative permeability. Here CO2-water displacements are studied by conducting CO2 flooding experiments in a sandstone core sample, considering the effects of CO2 phase, pressure and CO2 injection rate. The capillary pressure-saturation curve, water production behaviour and relative permeability are investigated for gas CO2-water, liquid CO2-water and supercritical CO2-water displacements in porous media. The pressure-dependant drainage capillary pressures are obtained as a result of CO2-water interfacial tension. Various water production behaviours are obtained for gas CO2-water and liquid CO2-water displacements, mainly due to the effect of CO2 dissolution. The significant irregular capillary pressure-saturation curves and water production behaviors can be observed for the supercritical CO2-water displacements. The water and CO2 relative permeabilities for CO2-water displacements in a porous media are then predicted.

Anthropogenic CO₂ captured from a coal-fired power plant can be used for an enhanced oil recovery (EOR) operation while mitigating the atmospheric impact of CO₂ emissions. Concern about climate change caused by CO₂ emissions has increased the motivation to develop carbon capture and sequestration (CCS) projects to reduce the atmospheric impact of coal and other fossil fuel combustion. Enhanced oil recovery operations are typically constrained by the supply of CO₂, so there is interest from oil producers to use large-volume anthropogenic (LVA) CO₂ for tertiary oil production. The intermittency of LVA CO2 emissions creates an area of concern for both oil producers and electric utilities that may enter into a CO₂ supply contract for EOR. An oil producer wants to know if intermittency from a non-standard source of CO₂ will impact oil production from the large volume being captured. Since the electric utility must supply electricity on an as-needed basis, the CO₂ emissions are inherently intermittent on a daily and seasonal basis. The electric utility needs to know if the intermittent supply of CO₂ would reduce its value compared to CO₂ delivered to the oil field at a constant rate. This research creates an experimental test scenario where one coal-fired power plant captures 90% of its CO₂ emissions which is then delivered through a pipeline to an EOR operation. Using real emissions data from a coal-fired power plant and simplified data from an actual EOR reservoir, a series of reservoir simulations were done to address and analyze potential operational interference for an EOR operator injecting large-volume, intermittent CO₂ characteristic of emissions from a coal-fired power plant. The test case simulations in this study show no significant impact to oil production from CO₂ intermittency. Oil recovery, in terms of CO₂ injection, is observed to be a function of the total pore volumes injected. The more CO₂ that is injected, the more oil that is produced and the frequency or rate at which a given volume is injected does not impact net oil production. Anthropogenic CO₂ sources can eliminate CO₂ supply issues that constrain an EOR operation. By implementing this nearly unlimited supply of CO₂, oil production should increase compared to smaller-volume or water-alternating-gas (WAG) injection strategies used today. Mobility ratio and reservoir heterogeneity have a considerable impact on oil recovery. Prediction of CO₂ breakthrough at the production wells seems to be more accurate when derived from the mobility ratio between CO₂ and reservoir oil. The degree of heterogeneity within the reservoir has a more direct impact on oil recovery and sweep efficiency over time. The volume of CO₂ being injected can eventually invade lower permeability regions, reducing the impact of reservoir heterogeneity on oil recovery. This concept should mobilize a larger volume of oil than a conventional volume-limited or WAG injection strategy that may bypass or block these lower permeability regions. Besides oil recovery, a reservoir's performance in this study is defined by its CO₂ injectivity over time. Elevated injection pressures associated with the large-volume CO₂ source can substantially impact the ability for an oil reservoir to store LVA CO₂. As CO₂, a less viscous fluid, replaces produced oil and water, the average reservoir pressure slowly declines which improves injectivity. This gradual improvement in injectivity is mostly occupied by the increasing volume of recycled CO₂. Sweep efficiency is critical towards minimizing the impact of CO₂ recycling on reservoir storage potential. Deep, large, and permeable oil reservoirs are more capable of accepting LVA CO₂, with less risk of fracturing the reservoir or overlying confining unit. The depth of the reservoir will directly dictate the injection pressure threshold in the oil reservoir as the fracture pressure increases with depth. If EOR operations are designed to sequester all the CO₂ delivered to the field, additional injection capacity and design strategies are needed. / text