<p> In this study, imbibition experiments are used to explain the significant fluid loss, often more than 70%, of injected water during well stimulation and flowback in the context of natural gas production from shale formations. Samples from a 180 ft. long section of a vertical well were studied via spontaneous and forced imbibition experiments, at lab-scale, on small samples with characteristic dimensions of a few cm; in order to quantify the water imbibed by the complex multi-porosity shale system. The imbibition process is, typically, characterized by a distinct transition from an initial linear rate (vs. square root of time) to a much slower imbibition rate at later times. These observations along with contact angle measurements provide an insight into the wettability characteristics of the shale surface. Using these observations, together with an assumed geometry of the fracture system, has made it possible to estimate the distance travelled by the injected water into the formation at field scale. </p><p> Shale characterization experiments including permeability measurements, total organic carbon (TOC) analysis, pore size distribution (PSD) and contact angle measurements were also performed and were combined with XRD measurements in order to better understand the mass transfer properties of shale. The experimental permeabilities measured in the direction along the bedding plane (10^&ndash;1&ndash;10^&ndash;2 mD) and in the vertical direction (~10^&ndash;4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10^&ndash;5 to 10^&ndash;8 mD). This implies that the fastest flow in a formation is likely to occur in the horizontal direction, and indicates that the flow of fluids through the formation occurs predominantly through the fracture and micro-fracture network, and hence that these are the main conduits for gas recovery. The permeability differences among samples from various depths can be attributed to different organic matter content and mineralogical characteristics, likely attributed to varying depositional environments. The study of these properties can help ascertain the ideal depth for well placement and perforation. </p><p> Forced imbibition experiments have been carried out to better understand the phenomena that take place during well stimulation under realistic reservoir conditions. Imbibition experiments have been performed with real and simulated frac fluids, including deionized (DI) water, to establish a baseline, in order to study the impact on imbibition rates resulting from the presence of ions/additives in the imbibing fluid. Ion interactions with shales are studied using ion chromatography (IC) to ascertain their effect on imbibition induced porosity and permeability change of the samples. It has been found that divalent cations such as calcium and anions such as sulfates (for concentrations in excess of 600 ppm) can significantly reduce the permeability of the samples. It is concluded, therefore, that their presence in stimulating fluids can affect the capillarity and fluid flow after stimulation. We have also studied the impact of using fluoro-surfactant additives during spontaneous and forced imbibition experiments. A number of these additives have been shown to increase the measured contact angles of the shale samples and the fluid recovery from them, thus making them an ideal candidate for additives to use. Their interactions with the shale are further characterized using the Dynamic Light Scattering (DLS) technique in order to measure their hydrodynamic radius to compare it with the pore size of the shale sample.</p><p>

<p> Detecting leaks is always a priority in the oil and gas industry and plays a major concern to human safety. The time required to fix any leak has a direct relationship in determining the damages caused to the environment, industry, and most importantly, the number of lives lost caused by catastrophic pipe failures. Detecting leak size and location in pipelines with higher accuracy presents major challenges to operators. This research work presents an innovative solution to locate a leak location inside a pipeline with higher precision. The solution is based on generating a 3D model that establishes a relationship between leak noise and its associated location and size. In order to generate the 3D model, an experiment study was first conducted where a flow loop having a leak, integrated with an acoustic detection system, was built to collect data about the effect of leak size, flowrate, pipeline material, and length on the noise generated. Later, a numerical study used the experimental results to initiate a simulation that aimed at finding how the leak noise propagates from the leak location. Finally, the experimental and numerical results were combined into a 3D model equation that solves for the leak location based on the leak noise and size.</p><p>

<p> The quest for affordable energy continues to drive the need for new technology and push the limits of current practice. In the offshore arena of oil and gas exploration, massive drillships are used to penetrate reservoirs several thousand feet below the surface. The dynamic loading in the landing and casing string induced by an ocean environment is studied and a simplified model of heave in the string is developed in this thesis. An overview of the landing operations for intermediate casing strings and factors driving increasing lengths and weights of casing are presented. The available wave energy spectra for simulating the ocean wave environment and the ship&rsquo;s response to such an environment (particularly in heave) are discussed. A literature review of previous models of dynamic loading in tubulars aboard offshore vessels is presented. The development and validation of a simplified model based on two real-world case studies are also presented. Contrary to prior assumptions, for models with 10 to 50 lumped masses, an increase in the number of masses significantly decreases the dynamic loads compared to using fewer masses. A comparison of the model results to the case studies suggests that vessel heave from the ocean environment induced only a portion of the dynamic loads observed. The dynamic loads observed in the case studies are on the order of only 1% of static string weight. Operations in extreme waves are also simulated, and the maximum dynamic loads predicted are less than 5% of static string weight.</p><p>

<p> Gas hydrates pose economic and environmental risks to the oil and gas industry when plug formation occurs in pipelines. A novel approach using interfacial rheology was applied to understand cyclopentane clathrate hydrate formation in the presence of nonionic surfactant to achieve hydrate inhibition at low percent weight compared to thermodynamic inhibitors. The hydrate-inhibiting performance of low (&lt;CMC), medium (&ap;CMC), and high (>CMC) concentrations of Span 20, Span 80, Pluronic L31, and Tween 65 at 2 &deg;C on a manually nucleated 2 &mu;L droplet showed a morphological shift in crystallization from planar shell growth to conical growth for growth rates below 0.20 mm²/min. Monitoring the internal pressure of a droplet undergoing planar hydrate crystallization provided a strong correlation (up to <i>R</i> = &ndash;0.989) of decreasing interfacial tension to the shrinking area of the water-cyclopentane interface. Results from the high-concentration batch of surfactants indicated that while initial hydrate growth is largely suppressed, the final stage of droplet conversion becomes rapid. This effect was observed following droplet collapse from the combination of large conical growths and low interfacial tensions. The low-concentration batch of surfactants saw rapid growth rates that diminished once hydrate shell coverage was completed. The most effective surfactant was the high-concentration Tween 65 (0.15 g/100mL), which slowed hydrate growth to 0.068 mm²/min, nearly an order of magnitude slower than that found for pure water at 0:590 mm²/min. High molecular weight (1845 g/mol) and HLB (10.5) close to 10 contribute to a large energy of desorption at an interface and are believed to be the sources of Tween 65's hydrate-inhibiting properties. </p><p>

Thesis (Ph.D.)--University of Adelaide, Australian School of Petroleum (ASP), 2004. / "February 2003" PhD (by publication). Includes bibliographical references.

Thesis (M.Eng.)--Memorial University of Newfoundland, 2005. / Bibliography: leaves 130-135.

The formation of ferrous phosphonate precipitate and its dissolution were monitored in a batch experiment for a range of temperatures and ionic strengths. The precipitate was found to be Fe$\sb{2.5}$HNTMP, where NTMP is a phosphonate compound. Using a complexation and speciation model, concentrations of free iron and phosphonate were calculated, from which the solubility product constant was derived for each temperature and ionic strength. The temperature (K) and ionic strength (M) dependence of the negative logarithm of the ferrous phosphonate solubility product constant $(pK\sb{\rm sp})$ was thus determined:$$pK\sb{\rm sp} = 39.54 - 6.14\sqrt{IS}+2.18IS - 1315/T.$$Simulated calculations using actual field data to compare iron and calcium phosphonates predicted ferrous salts to form in all instances and calcium salts to form occasionally. Further, a relationship was established whereby the concentration of free iron in a calcium-iron-phosphonate system can be predicted.

This thesis addresses several key issues in the design of foam processes in porous media. Laboratory experiments were performed to identify the conditions for the generation of strong foam. They demonstrated that strong foam in homogeneous porous media is obtained above a critical dimensionless number that represents the point when there are sufficient lamellae to create discontinuity in all flowing gas paths. The critical number corresponds to a critical pressure drop that scales inversely with the square root of permeability. The results imply that mobilization and division is the primary mechanism for the generation of strong foam in homogeneous media. Effects of heterogeneity on foam generation and propagation are studied. Steady-state analysis suggests snap-off occurring near permeability increase due to the drop in capillary pressure. Experiments in homogeneous and heterogeneous sand-packed columns revealed that the foam mobility in the two cases could indeed differ by two orders of magnitude, due to snap-off for flow across an abrupt increase in permeability. This mechanism of foam generation is dependent on the degree of permeability contrast and the gas fractional flow. At low gas fractional flow, a permeability contrast of at least about 4 is necessary. Snap-off also occurs when the increase in permeability is gradual. In this case, small capillary number (e.g. low flow rate) is required. A simple foam model was developed and incorporated into an existing reservoir simulation package. In addition to a fixed increase in foam effective viscosity---a feature that is common in many previous models, the increase in trapped gas saturation during imbibition is included. The latter is critical to model diversion in surfactant-alternating-gas processes. Observations from a field-scale foam application for aquifer remediation were reviewed. The reservoir simulator that included the foam model was successfully utilized to simulate the process and interpret its results. The field results are consistent with the conditions for strong foam and the effects of heterogeneity identified in the laboratory. Simulations indicated that foam mobility in the vertical direction, which is generally perpendicular to stratification, was about 1 to 2 orders of magnitude less than its horizontal mobility. The reduction in vertical mobility due to snap-off in stratified media implies that foam in field-scale processes should propagate farther than previously thought.

Thesis (Ph.D.)--University of Tulsa, 1993. / Includes bibliographical references (leaves 240-250).

Thesis (Ph. D.)--University of Texas at Austin, 1998. / Vita. Includes bibliographical references (leaves 232-237). Available also in a digital version from Dissertation Abstracts.