Drainage of a mobile, symmetric, plane-parallel thin liquid film between two gas bubbles (foam film) is studied. An analytical solution for the rate of thinning of such a liquid film with an insoluble surfactant and having both film elasticity and surface viscosity is presented for the first time. Analysis is extended to the more general case of a soluble surfactant and compared with previous analyses. Surfactant material parameters affecting the rate of thinning are identified and grouped into a single dimensionless parameter, the surfactant number which describes the transition from a mobile to an immobile film. Significant deviation from the Reynolds velocity is found when this dimensionless parameter is small. Since draining foam or emulsion films are generally of nonuniform thickness with a thick region or 'dimple' as the central part and separated from the Plateau border by a thinner 'barrier ring', an analytical solution is not possible. Hence a numerical model was developed. This model simulates the hydrodynamics associated with the drainage of an axisymmetric, dimpled, mobile foam film with an insoluble surfactant. This extends the work of Joye (1994) which was limited to immobile films. Results of the parametric study indicate that the rate of drainage of these films is dependent on surfactant properties viz. elasticity, surface dilatational viscosity, surface shear viscosity and surface diffusivity. These properties are grouped into a single dimensionless parameter which is the same as obtained by our analytical solution for a plane parallel film and which correlates with the rate of drainage of the foam film. This parameter describes the transition from a mobile film to an immobile film. The simulations indicate considerable motion of the interface for draining mobile foam films. Foam texture in a porous medium is governed by the hydrodynamics of individual foam films (lamellae) flowing through pores of varying size. The stability of foam in a particular application depends upon the stability of a lamella in the porous medium, especially as the lamella expands in translating from a small pore (pore throat) to a larger pore (pore body). The numerical simulator developed above is extended to translating foam films to model the effect of various parameters on foam stability. The model predicts that the travelling lamella is unstable only for certain ranges of surfactant properties, porous media geometry and flow conditions, for e.g. gas flow rate and capillary pressure. Simulations show that mobile foam films stretch in going from a pore throat to a pore body and may thin down to the critical thickness and break, under certain conditions. In contrast immobile foam films are very stable due to an entrainment effect which occurs as the film expands in going from a pore throat to a pore body. The critical capillary pressure at which a moving lamella will break is determined as a function of film and porous medium properties. Further the concept of asymmetric drainage of foam films in porous media has been explored.

Through isobaric temperature ramping experiments, the solubility of pure methane, ethane, propane, carbon dioxide gases and a methane-propane gas mixture in pure liquid water has been measured. The experiments are conducted at low temperatures and pressures corresponding to the clathrate hydrate formation and decomposition region. The inhibitory effect of a 10 weight percent methanol aqueous solution and a 0.5 weight percent polyvinylpyrrolidone aqueous solution on the hydrate formation and decomposition conditions has been estimated. A study of the pH-induced change in the hydrate stability has also been performed. The isobaric solubility data obtained show a significant divergence from Henry's law prior to and during hydrate formation. A molecular mechanism of hydrate nucleation is hypothesized, based on an analysis of the gas supersaturation observed and the current knowledge on the structure of liquid water.

Experiments and numerical simulations were carried out to improve the understanding of foam flow in underground porous media, especially three-dimensional foam flow, and to develop a numerical model for the design of the foam hydrogen sparging process for aquifer remediation. Injection of hydrogen is a promising method to enhance in situ anaerobic biodegradation of chlorinated solvents. The use of foam formed in situ by injection of hydrogen and a suitable surfactant solution greatly extends the horizontal migration of hydrogen in the subsurface, especially near the bottom of the aquifer where chlorinated solvents normally reside. The number of hydrogen injection wells required is thereby reduced. Experiments were conducted in a 2x2x2 foot glass tank filled with sand and instrumented to permit sampling or measurement of local pressure differences as a function of time at 36 points located at 9 lateral positions and four elevations. After the tank was filled with surfactant solution, gas was injected at constant pressure from one corner near the bottom of the tank. In some experiments the packing of the sand was homogeneous; in others it was layered. The experiments confirmed that foam greatly increases lateral gas distribution along the bottom as well as average gas saturation in the tank. A model was developed to simulate three-dimensional foam flow in porous media and was incorporated into the existing reservoir simulator UTCHEM. The model changes the gas relative permeability curve and gas viscosity from those of ordinary two-phase flow to represent the reduced gas mobility when foam is present. All except one parameter of the model can be obtained from foam experiments in one-dimensional sand columns. This parameter is a geometric factor, which accounts for the greater mobility of foam in three dimensions than in one dimension for similar conditions, presumably the result of the greater number of possible flow paths in three dimensions. A history match of several of the above tank experiments showed that if foam mobility in the tank was taken to be about five times greater than in a column, simulated average gas saturation, gas injection rate, gas distribution and pressure profile six inches above the bottom of the tank were in good agreement with experimental results for the homogeneous packing. For the layered packing it was also necessary to fit another parameter to the data to account for generation of additional foam by flow, of gas from lower to higher permeability regions. The simulator was used to design a foam hydrogen sparging process for a hypothetical aquifer. Results showed that with foam well spacing could be increased by 80% for a particular homogeneous aquifer while maintaining about the same sweep efficiency near the bottom of the aquifer.

This thesis addresses several key issues in the design of foam for mobility control in alkaline-surfactant enhanced oil recovery processes. First, foam flow in fracture systems was studied. A theory for foam flow in a uniform fracture was developed and verified by experiment. The apparent viscosity was found to be the sum of contributions arising from liquid between bubbles and the resistance to deformation of the interfaces of bubbles passing through the fracture. Apparent viscosity increases with gas fractional flow and is greater for thicker fractures (for a given bubble size), indicating that foam can divert flow from thicker to thinner fractures. The diversion effect was confirmed experimentally and modeled using the above theory for individual fractures. The amount of surfactant solution required to sweep a heterogeneous fracture system decreases greatly with increasing gas fractional flow owing to the diversion effect and to the need for less liquid to occupy a given volume when foam is used. The sweep efficiency's sensitivity to bubble size was investigated theoretically in a heterogeneous fracture system with log-normal distributed apertures. Second, the foam application in forced convection of alkaline-surfactant enhanced oil recovery processes was studied. From sand pack experiments for the alkaline-surfactant-polymer process, a 0.3 PV slug of the surfactant blend studied can recover almost all the waterflood residual crude oil when followed by a polymer solution as mobility control agent. But this blend is a weak foamer near its optimum salinity while one of its components, IOS, is a good foamer. Two types of processes were tested in sand packs to study possible process improvements and cost savings from replacing some polymer by foam for mobility control. The first used IOS foam as drive after the surfactant slug, while the second, which is preferred, involved injecting gas with the surfactant slug containing polymer followed by IOS foam. It was found that foam has higher apparent viscosity in high than in low permeability region. Thus, use of foam should be more attractive in heterogeneous system to get better sweep efficiency.

We use a MARAN-2 laboratory NMR spectrometer for making measurements using the CPMG pulse sequence for estimating the spin-spin or T$\sb2$ relaxation time distribution. Algorithms are developed for estimating the relaxation time distribution. Guidelines are given for designing the measurements to reduce measurement artifacts. The measured R-X channels data are transformed to the signal-plus-noise channel and the noise channel before using in the estimation of the relaxation time distribution. The reduction of the number of data by sampling and averaging decreases significantly the computational time. The optimum $\alpha$ (regularization parameter) depends on the corresponding slope of the plot of log$\rm\sb{10\chi A}$ versus log$\sb{10}\alpha.$ Further, this optimum slope in log-log scale is inversely proportional to the number of data. A systematic parametric study reveals that the broadening of the estimated relaxation time distribution can be reduced by decreasing the noise level, decreasing the echo spacing, or using a sufficient range of data.

No description available.

<p> Hydraulic fracturing was first carried out in the 1940s and has gained popularity in current development of unconventional resources. Flowing back the fracturing fluids is critical to a frac job, and determining well cleanup characteristics using the flowback data can help improve frac design. It has become increasingly important as a result of the unique flowback profiles observed in some shale gas plays due to the unconventional formation characteristics. </p><p> Computer simulation is an efficient and effective way to tackle the problem. History matching can help reveal some mechanisms existent in the cleanup process. The Fracturing, Acidizing, Stimulation Technology (FAST) Consortium at Colorado School of Mines previously developed a numerical model for investigating the hydraulic fracturing process, cleanup, and relevant physics. It is a three-dimensional, gas-water, coupled fracture propagation-fluid flow simulator, which has the capability to handle commonly present damage mechanisms. </p><p> The overall goal of this research effort is to validate the model on real data and to investigate the dominant physics in well cleanup for the Cana Field, which produces from the Woodford Shale in Oklahoma. </p><p> To achieve this goal, first the early time delayed gas production was explained and modeled, and a simulation framework was established that included all three relevant damage mechanisms for a slickwater fractured well. Next, a series of sensitivity analysis of well cleanup to major reservoir, fracture, and operational variables was conducted; five of the Cana wells' initial flowback data were history matched, specifically the first thirty days' gas and water producing rates. </p><p> Reservoir matrix permeability, net pressure, Young's modulus, and formation pressure gradient were found to have an impact on the gas producing curve's shape, in different ways. Some moderately good matches were achieved, with the outcome of some unknown reservoir information being proposed using the corresponding inputs from the history matching study. It was also concluded that extended shut-in durations after fracturing all the stages do not delay production in the overall situation. </p><p> The success of history matching will further knowledge of well cleanup characteristics in the Cana Field, enable the future usage of this tool in other hydraulically fractured gas wells, and help operators optimize the flowback operations. Future improvements can be achieved by further developing the current simulator so that it has the capability of optimizing its grids setting every time the user changes the inputs, which will result in better stability when the relative permeability setting is modified.</p>

<p> This thesis describes the advantages of investigating gas shales reservoir description on a nanoscale by using petrographic analysis and core plug petrophysics to characterize the Barnett, Marcellus and Mancos shale plays. The results from this analysis now indicate their effects on the reservoir quality. Helium porosity measurements at confining pressure were carried out on core plugs from this shale plays. SEM (Scanning Electron Microscopy) imaging was done on freshly fractured gold-coated surfaces to indicate pore structure and grain sizes. Electron Dispersive X-ray Spectroscopy was done on freshly fractured carbon-coated surfaces to tell the mineralogy. Extra-thin sections were made to view pore spaces, natural fractures and grain distribution. </p><p> The results of this study show that confining pressure helium porosity values to be 9.6%, 5.3% and 1.7% in decreasing order for the samples from the Barnett, Mancos and Marcellus shale respectively. EDS X-ray spectroscopy indicates that the Barnett and Mancos have a high concentration of quartz (silica-content); while the Mancos and Marcellus contain calcite. Thin section analysis reveals obvious fractures in the Barnett, while Mancos and Marcellus have micro-fractures. </p><p> Based on porosity, petrographic analysis and mineralogy measurements on the all the samples, the Barnett shale seem to exhibit the best reservoir quality.</p>

<p> Nuclear magnetic resonance (NMR) has become an increasingly important tool for estimating porosity, permeability, and fluid characteristics in oil and gas reservoirs since its introduction in the 1950s. While NMR has become common practice in <i>conventional</i> reservoirs, its application is relatively new to <i>unconventional</i> reservoirs such as the Eagle Ford Shale. Porosity and permeability estimates prove difficult in these exceptionally tight rocks and are routinely below the detection limit and/or resolution of low frequency (2 MHz or less) NMR. High frequency (400 MHz) NMR has been applied to address these issues; however, previous studies have been limited to crushed rock samples or millimeter-sized core plugs. </p><p> In response, a custom-built NMR probe has been constructed, capable of measuring 0.75-inch diameter, 0.45-inch length core plugs at 400 MHz, to determine if larger core plug sizes yield higher resolution <i>T</i>₂ distributions in the Eagle Ford Shale. The tool is composed of two primary elements, the structural framework and the radio frequency circuit. Each element was designed and constructed iteratively to test various layouts while maintaining functionality. The probe's structural design was initially based on retired, commercial probes then modified to operate within a Bruker Ascend&trade; 400WB NMR spectrometer. Designs were drafted and 3D-printed multiple times to determine proper physical dimensions and clearances. Once designs were deemed satisfactory, structural components were manufactured and assembled to create the structural framework. A radio frequency circuit was then built to measure <i>T</i>₂ distributions at the desired frequency and sample size. Multiple inductor designs and capacitor combinations were tested until a stable circuit, capable of matching impedance and tuning to the proper frequency, was achieved. The probe's stability and data quality were then confirmed by measuring the NMR spectra of deuterated water in a Teflon container. </p><p> The NMR probe was validated by comparing high frequency (400 MHz) data acquired in-house to low frequency (2 MHz) data measured at a commercial laboratory. Twelve core plugs (0.75-inch diameter, 1-inch length) were cut from two Eagle Ford Shale subsurface cores located in Gonzales and La Salle counties, Texas. Low frequency <i>T</i>₂ distributions were measured twice: first after drying core plug samples in a vacuum oven and again after spontaneous imbibition with various brine solutions (deionized water, 8 wt.% KCl, or 17.9 wt.% KCl) for one week. These contrasting saturation states were applied to highlight immovable water in the core plugs. For high frequency data measurements, samples were trimmed to 0.45-inch lengths to fit inside the newly-built NMR probe, leaving two sub-samples for each of the original core plugs. <i> T</i>₂ distributions were first acquired "as-is" (e.g., without drying or imbibition). After as-is data acquisition, samples were dried in a vacuum oven then allowed to spontaneously imbibe the same brine solutions used in the low frequency study. <i>T</i>₂ distributions were measured again after imbibition and compared to the low frequency data acquired by the commercial laboratory. </p><p> Qualitatively, high frequency <i>T</i>₂ distributions resemble low frequency data; however, the absolute <i>T</i>₂ values are routinely higher by one order of magnitude. The difference may be caused by data acquisition, data processing, fluid-rock interactions, magnetic field inhomogeneities, or some combination thereof. In spite of not attaining the higher-resolution <i>T</i>₂ distributions desired, the project still provides a proof-of-concept that <i>T</i>₂ relaxation times can be measured in conventional-sized core plugs using 400 MHz NMR. Although limited in its outcomes, the study delivers promising results and elicits future research into utilizing high frequency NMR spectroscopy as a petrophysical tool for unconventional reservoirs.</p><p>

<p> Reactive transport phenomena, such as CO2 sequestration and Microbial EOR, have been of interest in streamline-based simulations. Tracing streamlines launched from a wellbore is important, especially for time-sensitive transport behaviors. However, discretized gridblocks are usually too large as compared to the wellbore radius. Field-scale simulations with local-grid-refinement (LGR) models often consume huge computational time. An embedded grid-free approach to integrate near-wellbore transport behaviors into streamline simulations is developed, which consists of two stages of development: tracing streamlines in a wellblock (a gridblock containing wells) and coupling streamlines with neighboring grids. The velocity field in a wellblock is produced based on a grid-less virtual boundary element method, where streamlines are numerically traced using the fourth-order Runge-Kutta (RK4) method. The local streamline system is then connected with the global streamline system which is produced by Pollock&rsquo;s algorithm. Finally, the reactive transport equation will be solved along these streamlines. </p><p> The presented algorithm for solving near-wellbore streamlines is verified by both a commercial finite element simulator and Pollock-algorithm-based 3D streamline simulator. A series of computational cases of reactive transport simulation are studied to demonstrate the applicability, accuracy, and efficiency of the proposed method. Velocity field, time-of-flight (TOF), streamline pattern, and concentration distribution produced by different approaches are analyzed. Results show that the presented method can accurately perform near-wellbore streamline simulations in a time-efficient manner. The algorithm can be directly applied to one grid containing multiple wells or off-center wells, as well. Furthermore, assuming streamlines are evenly launched from the gridblock boundary or ignoring transport in the wellblock is not always reasonable, and may lead to a significant error. </p><p> This study provides a simple and grid-free solution, but is capable of capturing the flow field near the wellbore with significant accuracy and computational efficiency. The method is promising for streamline-based reservoir simulation with time-sensitive transport, and other simulations requiring an accurate assessment of interactions between wells in one particular gridblock.</p><p>