The primary objective of this study was to quantify and characterise lipid deposition on soft (hydrogel) contact lenses, particularly those containing siloxane components. Studies involving a variety of <em>in vitro</em> doping and <em>in vivo</em> worn contact lenses were undertaken, in which lipid deposition was analyzed by either TLC or HPLC. Specific experiments were completed to optimize a method to extract the lipid from the lens materials, to compare the total lipid deposition on nine different hydrogel lenses and to analyze the effect that lipid deposition had on wettability. A method for extracting lipid from contact lenses using 2:1 chloroform: methanol was developed. This study also showed that siloxane-containing contact lens materials differ in the degree to which they deposit lipid, which is dependent upon their chemical composition. Small differences in lipid deposition that occur due to using variations in cleaning regimens were not identifiable through TLC, and required more sophisticated analysis using HPLC. Contact lens material wettability was found to be influenced by <em>in vitro</em> lipid deposition. Specifically, conventional hydrogels and plasma surface-treated silicone-hydrogel materials experienced enhanced wettability with lipid deposition. Reverse-phase HPLC techniques were able to quantify lipid deposits with increased sensitivity and accuracy. From the HPLC studies it was found that contact lens material, concentration of the lipid doping solution, and the composition of the lipid doping solution in <em>in vitro</em> deposition studies influenced the ultimate amount and composition of lipid deposits. <em>In vivo</em> HPLC studies showed that the final lipid deposition pattern was influenced by the interaction between the composition of the tear film and the various silicone hydrogel contact lens materials. In conclusion, HPLC analysis methods were more sensitive and quantitative than TLC. Lipid deposition was ultimately influenced by the concentration and composition of the lipid in the tear film and the contact lens material. Contact lens wettability was influenced by the presence and deposition of lipid onto the contact lens surfaces. Finally, this reverse-phase HPLC lipid analysis protocol was not the most sensitive, robust, or accurate. In the future, other methods of analysis should be explored.

Carbonate reservoirs are heterogeneous; therefore, proper acid placement/diversion is required to make matrix acid treatments effective. Viscoelastic surfactants (VES) are used as diverting agents in carbonate matrix acidizing. However, these surfactants can adversely affect wettability around the wellbore area. Lab and field studies show that significant amounts of VES are retained in the reservoir, even after an EGMBE postflush. Optimizing acid treatments requires a study of the effect of VES on wettability. In a previous study using contact angle experiments, it was reported that spent acid solutions with VES only, and with VES and EGMBE are water-wetting. In this thesis, we studied the effect of two amphoteric amine-oxide VES', designated as "A" and "B" on the wettability of Austin cream chalk using contact angle experiments. We extended the previous study by using outcrop rocks prepared to simulate reservoir conditions, by demonstrating that VES adsorbs on the rock using two-phase titration experiments, by studying the effect of temperature on wettability and adsorption, and by developing a detailed procedure for contact angle experiments. We found that for initially oil-wet rocks, simulated acid treatments with VES "A" and "B" diversion stages and an EGMBE preflush and postflush made rocks water-wet at 25, 80, and 110 degrees C. Simulated acid treatments with a VES "A" diversion stage only made rocks water-wet at 25 degrees C. Our results suggest that both VES formulations cause a favorable wettability change for producing oil. The two-phase titration experiments show that both VES "A" and "B" adsorb on the rock surface. From our literature review, many surfactant wettability studies use contact angle measurements that represent advancing contact angles. However, wettability during stimulation is represented by receding contact angles. Results of static receding contact angles may be misinterpreted if low oil-acid IFT's cause oil droplets to spread. Spreading could be a reflection of the effect of the surfactants on the fluid-fluid interface rather than the rock-fluid interface. The new procedure shows the effect of VES and EGMBE on the rock-fluid interface only, and so represents the actual wettability.

This study successfully demonstrates the electrical control of the surface wettability of liquid crystal and polymer composite film. The application of external voltages significantly affects the surface wettability of the film. This study uses atomic force microscopy to quantitatively characterize the fundamental mechanism responsible for the structurally driven changes in surface properties at various applied voltages. The surface wettability transitions of the film are electrically driven, as shown by reorganized liquid crystal molecules. Measurements of the voltage-dependent surface wettability of the composite film suggest novel approaches to supporting control applications of future electro-optical nanotechnology devices, including liquid lenses, windshields and displays.

The demand for energy and new oil reservoirs around the world has increased rapidly while oil recovery from depleted reservoirs has become more difficult. Oil production from fractured carbonate reservoirs by water flooding is often inefficient due to the commonly oil-wet nature of matrix rocks. Chemical enhanced oil recovery (EOR) processes such as surfactant-induced wettability alteration and interfacial tension reduction are required to decrease the residual oil saturation in matrix blocks, leading to incremental oil recovery. However, improvement in recovery will depend on the degree of wettability alteration and interfacial tension (IFT) reduction, which in turn are functions of matrix permeability, fracture intensity, temperature, pressure, and fluid properties. The oil recovery from fractured carbonate reservoirs is frequently considered to be dominated by the spontaneous imbibition mechanism which is a combination of viscous, capillary, and gravity forces. The primary purpose of this study is to model wettability alteration in the lab scale for both coreflood and imbibition cell tests using the chemical flooding reservoir simulator. The experimental recovery data for fractured carbonate rocks with different petrophysical properties were history-matched with UTCHEM, The University of Texas in-house compositional chemical flooding simulator, using a highly heterogeneous permeability distribution. Extensive simulation work demonstrates the validity and ranges of applicability of upscaled procedures, and also indicates the importance of viscous and capillary forces in larger fields. The results of this work will be useful for designing field-scale chemical EOR processes. / text

The effect of brine ionic composition on oil recovery was studied for a limestone reservoir rock at a high temperature. Contact angle, imbibition, core flood and ion analysis were used to find the brines that improve oil recovery and the associated mechanisms. Contact angle experiments showed that modified seawater containing Mg[superscript 2+] and SO4[superscript 2-] and diluted seawater change aged oil-wet calcite plates to more water-wet conditions. Seawater with Ca[superscript 2+], but without Mg[superscript 2+] or SO₄[superscript 2-] was unsuccessful in changing calcite wettability. Modified seawater containing Mg[superscript 2+] and SO₄[superscript 2-], and diluted seawater spontaneously imbibe into the originally oil-wet limestone cores. Modified seawater containing extra SO₄[superscript 2-] and diluted seawater improve oil recovery from 40% OOIP (for formation brine waterflood) to about 80% OOIP in both secondary and tertiary modes. The residual oil saturation to modified brine injection is approximately 20%. Multi ion exchange and mineral dissolution are responsible for desorption of organic acid groups which lead to more water-wet conditions. Further research is needed for scale-up of these mechanisms from cores to reservoirs. / text

Altering the wettability of reservoir rock using fluoro-chemical treatments has proved to be a viable solution to the condensate blocking problem in gas wells. Alteration of rock wettability to neutral-wet is the primary reason for improvement in gas and condensate relative permeabilities. Stability/compatibility test, drop tests and X-ray photoelectron spectroscopy (XPS) analysis along with core flood results were used to characterize wettability changes. XPS tests, drop tests, and relative permeability measurements were conducted and correlated with each other. It is shown that XPS analysis and imbibition tests provide a quantitative measure of chemical adsorption and surface modification, but only a qualitative measure of the possible change in relative permeability. As such these simple analytical tools may be used as a screening tool. A positive but imperfect empirical correlation was obtained with results from core flood experiments. The varying concentration of fluorine observed on the rock surface was found to be directly correlated to the wettability change in the rock, which in turn is responsible for improving the deliverability of wells in gas condensate/volatile oil reservoirs. The method discussed in this thesis can be used to identify chemical treatments to change rock wettability and, therefore, relative permeability. This provides a simple, quick and inexpensive way to screen chemicals as wettability altering agents and relative permeability modifiers which saves time, cost and effort. / text

Many producing volatile oil reservoirs experience a significant decrease in well deliverability when the bottom-hole pressure of the well falls below the bubble point pressure. This is due to the liberation of a gas phase which resides in the pore space and blocks the flow of the oil phase. This situation is known as "gas blocking". This occurs because the presence of two or three immiscible phases (gas, oil and water) results in a reduction of the oil saturation and a decrease in the oil relative permeability. The main objective of this research was to develop an effective and durable chemical treatment method to improve and/or restore the productivity of volatile oil wells undergoing "gas blocking". The treatment method is based on the use of fluorinated surfactants in tailored solvents to increase the oil relative permeability by changing the wettability of the rock’s surface. High-temperature high-pressure (HTHP) core flood experiments were used to evaluate the uses of fluorinated surfactants under reservoir conditions. Analytical tools such as X-ray photoelectron spectroscopy (XPS), high-performance liquid chromatography (HPLC) and computerized axial tomography (CT Scan) were also used to interpret the experimental results. High-pressure high-temperature (HPHT) coreflood tests showed that the treatments improved the oil and gas relative permeability in both sandstone and limestone cores. This was observed for synthetic volatile oil mixtures with gas-oil ratios (GOR) in the range of 4000 to 13,000 scf/STB at low capillary numbers (Nc) on the order of 1x10-5 to 1x10-6 and for PVT ratios greater than 0.5. The fluorinated chemical treatments were effective in the presence of connate water over the temperature range of 155°F to 275°F. Wettability alteration was measured using contact angle and imbibition rate tests. Results from analytical tools showed that fluorinated surfactants were uniformly adsorbed along the core and the surfactant desorption after treatment was low (10 ppm or less). The gas saturation decreased following treatment and both the oil and gas relative permeability increased. Numerical simulations using the measured relative permeability data were used to estimate the gain in productivity for treated wells. The proposed fluorinated chemical treatments could be used as a preventive treatment or for a damaged well that has already been producing below the bubble point to increase oil production rates and recoverable reserves. / text

Spontaneous imbibition of water into Fontainebleau Sandstone matrix because of capillary gradient is an important mechanism for oil recovery from Fontainebleau Sandstone reservoirs. Spontaneous imbibition characteristics of Fontainebleau Sandstone core were determined by measuring the Wettability Index of four Fontainebleau Sandstone core samples under laboratory conditions. This was done by utilizing a combination of a Benchtop Relative Permeameter Flooding System and Amott Cups. The specimen had a diameter of 38mm and a height of 47mm. Permeability and porosity of the cores varied from 12 to 14 mD and 10 to 14% respectively. The fluids and chemicals used were kerosene, synthetic brine and Sodium dodecyl sulphate. Amott’s method was used to measure the wettability index. This method consists of four steps: (1) brine flooding, (2) spontaneous imbibition of brine, (3) kerosene flooding, (4) spontaneous imbibition of kerosene. One core was saturated with kerosene and then flooded with brine, followed by spontaneous imbibition of brine. Similarly, another core was saturated with brine and then flooded with kerosene, followed by spontaneous imbibition of kerosene. Similar procedures were used for other two cores except the addition of surfactant to the synthetic brine. All cores were then cleaned and re-saturated for spontaneous imbibition of kerosene and brine. All Experiments were performed under laboratory temperature conditions. Oil and water wettability values were obtained along with secondary and tertiary oil recoveries. These values were used to calculate the wettability index of Fontainebleau sandstone cores. Spontaneous imbibition characteristics of the cores obtained from the experimental data indicate that Fontainebleau Sandstone formation is a potential candidate for Secondary and Tertiary oil recovery by water injection and spontaneous imbibition.

This thesis presents the study of films derived from the reduction of aryldiazonium salts at gold surfaces. The properties of bare polycrystalline surfaces were investigated via the observation of the electrochemical oxidation and reduction of the gold. Films derived from diazonium salts were electrochemically grafted to the gold surface. The structure and stability of these interfaces was examined through the use of redox probes, gold oxide electrochemistry and water contact angle measurements. The spontaneous reduction of aryldiazonium salts at gold surfaces was investigated and the possible applications it presented towards printing and patterning of the gold surface with films were explained. Polycrystalline gold surfaces were prepared and subjected to various treatments, to observe the behaviour of gold oxide formation and reduction at the surface. Various effects on the surface structure were observed after treatment in solvents and electrolyte solutions. The surface structure of the gold atoms frequently changed due to the high mobilities of the gold atoms, and it is difficult to achieve a reproducibly stable surface. The electrochemical modification of gold surfaces via the reduction of aryldiazonium salts was investigated. Surfaces were modified with methylphenyl and carboxyphenyl films and exposed to various treatments. Monitoring the gold oxide reduction changes enabled the surface coverage of modifier directly attached to the surface to be calculated. The films appear to be stable, loosely packed and porous. The films are flexible in nature; redox probe responses showed reversible changes after repeated sonication in solvents of differing polarities and hydrophilicities. Contact angle measurements further support the notion of films that can reorganise in response to their environment. The spontaneous reduction of aryldiazonium salts at gold surfaces was observed. Film coverage was significantly lower at the spontaneously grafted surface than for films grafted electrochemically. Gold surfaces were successfully modified via microcontact printing, and surface coverages similar to the spontaneously grafted film were achieved. Microcontact printing was also used to pattern surfaces with films derived from diazonium salts. Feature sizes down to 100 µm were successfully achieved.

Injection of low-salinity water showed high potentials in improving oil recovery when compared to high-salinity water. However, the optimum water salinity and conditions are uncertain, due to the lack of understanding the mechanisms of fluid-rock interactions. The main objective of this study is to examine the potential and efficiency of low-salinity water in secondary and tertiary oil recovery for sandstone reservoirs. Similarly, this study aims to help in understanding the dominant mechanisms that aid in improving oil recovery by low-salinity waterflooding. Furthermore, the impact of cation type in injected brines on oil recovery was investigated. Coreflood experiments were conducted to determine the effect of water salinity and chemistry on oil recovery in the secondary and tertiary modes. The contact angle technique was used to study the impact of water salinity and composition on rock wettability. Moreover, the zeta potential at oil/brine and brine/rock interfaces was measured to explain the mechanism causing rock wettability alteration and improving oil recovery. Deionized water and different brines (from 500 to 174,000 mg/l), as well as single cation solutions were tested. Two types of crude oil with different properties and composition were used. Berea sandstone cores were utilized in the coreflood experiments. Coreflood tests indicated that injection of deionized water in the secondary mode resulted in significant oil recovery, up to 22% improvement, compared to seawater flooding. However, no more oil was recovered in the tertiary mode. In addition, injection of NaCl solution increased the oil recovery compared to injection of CaCl2 or MgCl2 at the same concentration. Contact angle results demonstrated that low-salinity water has an impact on the rock wettability; the more reduction in water salinity, the more a water-wet rock surface is produced. In addition, NaCl solutions made the rock more water-wet compared to CaCl2 or MgCl2 at the same concentration. Low-salinity water and NaCl solutions showed a highly negative charge at rock/brine and oil/brine interfaces by zeta potential measurements, which results in greater repulsive forces between the oil and rock surface. This leads to double-layer expansion and water-wet systems. These results demonstrate that the double-layer expansion is a primary mechanism of improving oil recovery when water chemical composition is manipulated.