<p>A high-pressure CO2 foam was generated with silica nanoparticle dispersion and CO2 for fracturing applications. The effects of different ions and temperature on nanoparticle aggregation were studied. Nanoparticle dispersions were mixed with individual monovalent, divalent ions with varying concentrations, and two synthesized Permian connate water solutions. Samples of nanoparticle dispersions with the presence of NaCl were put into chambers with constant temperature for 14 hours. The peak size of aggregated nanoparticles in each sample was measured. It was found this silica nanoparticle dispersion had a high thermal stability up to 85?. The silica nanoparticle dispersion used in this study maintained a desired stability under an 18% reservoir salinity condition, yet it could be sensitive to high concentrations of Na2SO4 solutions. To investigate foam rheology and stability, high-pressure CO2 foams were generated in a beadpack with different CO2/NP ratios in NaCl solutions. The resulting foam was observed in a sapphire tube. The differential pressure across a capillary tube was recorded to calculate the apparent viscosity of foams. Nanoparticle-stabilized foams could remain stable for days and foam stability decreased with the increasing foam quality. Foam apparent viscosity was found to increase with foam quality and could be 3 times as high as that of the ambient phase. The high stability and fine texture of high-pressure CO2-in-water foams stabilized by silica nanoparticles have broadened the development of foam fracturing, offering a new opportunity for the effective development and stimulation of unconventional reservoirs.

<p>The essence of many issues in different fields is the transport and piling of particles in fluid within a limited space. A semi-analytical model is developed in this study to describe the motions of a particle in fluid and simulate the piling process of particles in a fracture. As a result, the configuration of a particle pile and the time at which the pile totally seal the fracture face are predicted. This model possesses a wide range of applications. Two types of applications of this model are introduced, including the prediction of proppant screen-out in hydraulic fracturing vertical and horizontal wells and the simulation of curing the lost circulation. Results of case studies are consistent with the field data with minor errors. Sensitivity analyses with the proposed model were conducted for each type of application. Major factors affecting the model calculation results are identified for the purpose of optimizing the performance of hydraulic fracturing and curing the lost circulation. Sensitivity analyses conducted for the proppant screen-out prediction during fracturing vertical and horizontal wells indicate following conclusions: 1) The use of high fluid viscosity can avoid the premature settlement of proppant and significantly delay the screen-out time. 2) The sse of proppant with low density in the practical range could delay the screen-out time, but the effect is not as significant as other factors analyzed in this study. 3) A high injection rate allows the proppant pile to build farther from the wellbore, while it will lead to a quick screen-out. 4) Larger proppant size can easily cause screen-out sooner. 5) Wide distributionof proppant size can delay screen-out. 6) The use of low ratio of proppant volume to fluid volume can minimize the probability of the occurrence of screen-out. Sensitivity analyses for the cure of lost circulation demonstrate following conclusions: 1) Lost circulation can be cured faster when low fluid viscosity is used. 2) High density LCM can facilitate the cure of lost circulation. 3) Low mud density can mitigate lost circulation, but its effect is not as significant as other factors. 4) The concentration of LCM should be determined based on the severity of lost circulation. This semi-analytical model provides engineers a general tool to solve different issues involved in different fields. It can also be utilized to identify main factors responsible for different issues to minimize their detrimental effects.

<p> Ceramic proppants are commonly used in hydraulic fractures. However, people typically focus on controlling properties of proppants such as the material, specific gravity, and particle size, and less attention is paid to the effect of proppant wettability. The purpose of this study is to investigate the effect of proppant wettability on two-phase flow efficiency in fractured water-wet sandstones. The results show that oil-wet proppants are more effective in improving oil flow efficiency than water-wet proppants in both low-water saturation cores and high-water saturation cores. Therefore, small sized oil-wet proppants have better performance than large sized oil-wet proppants. </p><p>

<p> Hydraulic Fracturing is a cost-effective technique that has been widely integrated and applied to commercial production of oil and gas from unconventional reservoirs. Advancement of this technique brings more complexity into it, making optimization process more complicated in terms of economic analysis and decision making. Selection of proppant for treatment is a crucial and essential decision that has a significant impact on fracturing stimulation and well economics. This analysis indicates advantages and disadvantages of different types of proppant and provides a comparison of proppant performances considering proppant type, mesh size and concentration in order to identify the best scenario of proppant application in terms of economical profitability. </p><p>

<p> Abstract In this work, we studied the Eagle Ford Shale and experimented in detail to create a baseline to address the relative permeability of specific ions in shale. The study identifies that: (1) Ions are dispersed in a specific sequence (Na⁺, Ca²⁺, Mg²⁺). (2) As ions are dispersed, this allows the gas bubbles out of the shale/soil and forces the flakes and fragments to float to the top of the water on the vessel. The floating particles, depending on the type of cations released from the shale mass move towards a specific ion electrode. (3) Detachment or bursting of gas bubbles may initiate a shift or break in the shale/soil formation. (4) Calcium electrical potential, Eh, goes from negative to positive. This indicates an unstable potential with respect to time around the length of the well bore. (5) The release of ions depends on the diffusion properties of water penetrating the shale/soil mass. The motion of the shale/soil floating material is a vortex-like motion. </p><p> We conclude that by using SAR, it will help predict where the wellbore is stable or unstable based on the curve where certain drops or peaks or located. By creating a baseline measure using deionized water it is possible to predict the relative permeability of wellbore drilling of the Eagle Ford Shale using SAR. </p><p> Taking note of the ionic relative permeability as observed in our experiments, we decided to use the SAR method for estimating the relative permeability of shale/soil to various ions. All of this is based on where the most ionic flow occurs under given wellbore conditions. This understanding is further applicable to the design of certain type of frac fluids or design of a compatible drilling fluid for drilling a specific shale/soil.</p><p>

<p> The lack of cutting transportation during drilling operations can lead to large amounts of non productive time and costly solutions to address the issue. The objective of this study was to investigate the cutting velocity through an experimental approach. Dimensionless groups were formed based on the independent variables that affected cutting velocity. The experimental approach was analyzed through film software, which allowed for the cutting velocities to be calculated. Regression models of cutting velocity with respect to each dimensionless group were formed and validated through a statistical analysis. Only the second dimensionless group (?2) representing the volume of cuttings injected into the drillpipe with respect to the cubed value of the outer diameter of the drillpipe was proven to be insignificant. </p><p> Once the remaining regression models were validated, multiple linear regression analyses were conducted to relate each dimensionless parameter to the cutting velocity. This introduced a new empirical model to represent the cutting velocity based on the five significant dimensionless groups outlined in this study. The multiple linear regression model yielded an R-squared value of .81, which suggests a strong correlation for the data. This model was also validated through statistics. Each parameter except for the intercept of the model was confirmed to be significant. Other parameters that were excluded from the model due to the lack of equipment precision could be examined. A sensitivity analysis was conducted to highlight how each dimensionless group directly affected the cutting velocity. New correlations and trends may be estimated with more data from additional experiments outside the range of this study. Overall, this will allow the foundation of the model to be further improved.</p><p>

<p> Superhydrophobic coating reduces the fluid/solid interaction leading to ultra-hydrophobicity or the Lotus effect. The objective of this study is to determine how this phenomenon can be applied in petroleum production systems to enhance fluid flow in propped fractures using superhydrophobic coating on the surface of proppants. Permeability and wettability of coated sandstone samples are compared with the non-coated ones to create a base case for the study. Later sand packs are tested to determine the magnitude of enhancement in fracture conductivity after the modification is applied on sand proppants. The samples are measured for their absolute permeability and relative permeabilities to test the changes in flow for both the single-phase and two-phase fluid flow. The test results show a considerable increase of up to 98% for the single-phase flow and a 23% for the two-phase flow for the sand pack samples. The wettability test confirms that the coating modifies the samples from its initial water-wet state to a partial-wet state. Since the production rate of tight and shale reservoirs is low especially in liquid-rich reservoirs, a significant amount of water is injected for reservoir stimulation; enhancement in fracture conductivity as a result of proppant surface modification can have a meaningful impact on the recovery of these reservoirs. This study uses experimental techniques to show the effectiveness of superhydrophobic coating on the reduction of friction which can lead to enhancement in fracture conductivity. </p><p>

Polyamide-11 (PA11) is a polymer of the Nylon family whose monomer is obtained from the castor bean, a renewable resource. It is widely used in offshore oil and gas production as a non-rigid flexible pipe liner, allowing for oil and gas transport from the wellhead to floating platforms for processing. The degradation of PA11 over time may lead to the pipe's failure, with possibly catastrophic results which include loss of life. Until now, the characterization of the degredative process has been limited to laboratory studies of the effects of water and temperature on the rate and degree of hydrolysis. In this dissertation, a more exact model than those proposed in the literature thus far is defined and used to quantify the effects of temperature on the rate and degree of PA11 hydrolysis. This is performed using accelerated aging experiments in the lab which are evaluated by a primary means of molecular weight determination, size exclusion chromatography---multiple angle laser light scattering (SEC-MALLS). The effects of methanol and ethanol, used in the industry to control solid hydrate formation, are then characterized with respect to concentration and temperature, a topic which has not yet been addressed in the literature. Also novel to this work is the discovery of the effects of acetic acid, valeric acid, and 3-cyclopropionic acid on the rate and degree of PA11 hydrolysis. While these acids are present in the offshore oil and gas environment, acetic acid is the most common, and has been identified as a serious factor affecting degradation. The effects of acetic acid on rate and degree of hydrolysis are incorporated into the temperature dependence described above, and adapted to a model well suited for characterizing the degradation of PA11 in the changing temperature environments found in the field. By characterizing coupons removed from PA11 pipes in oil production fields in various parts of the world, the model is tested and used to predict aging of PA11 pipe. The model is shown to be effective at predicting degredation for times greater than ten years, which has never before been described. The effects of annealing coupled with decline in molecular weight on PA11 mechanical properties in accelerated aging experiments versus aging in the field environment is discussed. These contributions to understand and predict the aging of PA11 flexible pipes are central to increasing the safety of offshore oil and gas production, a topic that today is vastly important.

<p>This Master Thesis work aims to find a model system combining the positive effects of surfactant and polymer flooding to enhance oil recovery. This report presents the results of 12 core floors performed to enhance recovery of waterflood residual oil. The recovery is enhanced by a visous surfactant flood consistent of one polymer to increase the viscosity, one surfactant for interfacial tension reduction, and one di-alcohol to function as co-surfactant and for salinity control.</p><p>The chemical treatment that gave the best result, gave an additional oil production normalized on OOIP of 20%, improving the oil recovery from 45 to 66% mostly by the means of mobility control. Pure viscosity floods gave an additional recovery of 12 to 13% of OOIP.</p><p>Novel technology is used to investigate environmental friendly enhanced oil recovery. A biopolymer made out of microfibrils from wooden material was for the first time ever to my knowledge, attempted used in a core flood to enhance oil recovery.</p><p>A viscous surfactant tertiary recovery process may help improve oil recoveries from many marginal oil fields or those that face shut-down due to uneconomic operating costs, but still contain significant amounts of oil. </p>

Thesis (M. S.)--Texas A&M University, 2005. / "Major Subject: Petroleum Engineering" Title from author supplied metadata (automated record created on Sep. 15, 2006.) Vita. Abstract. Includes bibliographical references.