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The ability to evaluate rock and fluid properties on the order of a few microns opens new areas in reservoir engineering and reservoir simulation. Multiple studies have been done on the application of x-ray computed tomography (microCT) for the pore-scale evaluation of fluid interfaces and rock-fluid interaction. A majority of the fluid flow governing interactions occur at the pore scale level and is usually overseen on large reservoir scales. Hence, it is important to carefully investigate such interactions. Multi-fluid-phase distribution and interaction of two immiscible fluids such as oil and water is one of the most important and constantly investigated subjects in the oil and gas industry. Oil-water interaction is a complex phenomenon governed by various flow mechanisms in addition to fluid and rock physical properties. Wettability is one of the major concepts of the fluid flow through the porous media and a physical property of the rock that influences hydrocarbon recovery and the recovery methods. Oil and water phase distribution and residual blob configurations in water-wet and oil-wet Berea sandstone cores were successfully identified using x-ray computed tomography. Residual and remaining oil saturations were calculated from the obtained images. Rock porosity was calculated using indicator kriging segmentation technique and fluid saturations were calculated using watershed segmentation. Residual oil blob geometry in the water-wet core was successfully obtained from the segmented images. Oil saturations and phase configurations were in agreement with the oil saturation estimations obtained through the capillary desaturation analysis.

The number of well integrity issues increase as wells are exposed to severe downhole conditions and have longer lifetimes. Techniques for heat extraction from geopressured geothermal reservoirs involve production of hot water and injection of cold water which expose downhole materials to harsh cyclic temperature variations. Heating and cooling make the cement expand and contract as a result of thermal expansion. This volumetric change can influence cement sheaths causing them to fail. Failure of annular cement sheaths can introduce well integrity issues and subsequently lead to sustained casing pressure. This study measures the effect of cyclic thermal loading of cement slurry designs in salt brines. Grain volume porosimeter and Liquid Pressure-pulse Decay Permeameter was used to quantify the presence of thermal fractures as it is capable of measuring brine permeability of cement under reservoir conditions. Scanning Electron Microscopy micrographs with Energy Dispersive Spectroscopy capabilities, Thermogravimetric analysis and X-Ray Photoelectron Spectroscopy were used to study the physical and chemical changes in the cement slurry designs. Five cement designs with a range of chemical additive were subjected to 100 thermal cycles of 40⁰C at 100% relative humidity in salt brine. The experimental result indicates leaching of Ca(OH)2 will occur from the cement irrespective of cement composition which causes the porosity and permeability of the cement sheath to increase. Due to the thermal cycling, the strength of the cement sheath decrease. The study also shows that steel fiber can be added to the design to improve the permeability and increase the strength of the cement sheath under thermal cycle loading conditions. Future work is essential in order to fully understand within which temperature ranges a particular well can be operated, without leaks along the annular cement sheaths. This can be obtained by conducting tests varying the different materials in the cement mix. In addition, experimental tests determining the effect of exposing the formation to drilling fluids prior to cementing and further thermal cycling can be conducted. Effect of various wellbore scaling ratios is also important, as the effects of the total volumes on the obtained results are unknown.

Previous practice to determine the source mechanism of microseismic events associated with hydraulic fracture typically includes only far-field terms in moment tensor inversion. The intermediate-field terms and near-field term are normally ignored because of increased complexity in the calculation. Source-receiver distances in hydraulic fracturing are usually 1000 ft and the effects of near and intermediate-field terms are still unknown. We perform a study to improve the precision of the source mechanism by including the intermediate-field term in moment tensor inversion. We find that the intermediate-field term contributes 1/3 of the signal amplitude when the source-receiver distance is 1000 ft. The intermediate-field term contributes 1/20 of the signal amplitude when the source-receiver distance is 6700 ft. Note that "1/20" is at the noise level. Thus, when source-receiver distance is less than 6700ft, we need to consider the intermediate-field term. Especially, when the distance is 1000ft, the intermediate-field term becomes significant. Similarly, near-field terms contribute less than 1/20 of the signal amplitude when distances are larger than 300 ft. In our case, we confirm that the near-field term can be ignored in microseismic analysis. Our results indicate that the intermediate-field terms can improve moment tensor inversion by 2% to 40% at source-receiver ranges less than 1000 ft. When distances are larger than 6700, the improvement is limited to 1%. In the presence of noise, the intermediate-field terms help to improve the moment tensor inversion (15% improvement with noise present vs 3% improvement without noise). Our study provides a foundation for using intermediate-field terms in moment tensor inversion in the studies of hydraulic fractures.

In the oil and gas industry, reliable and accurate measurements of the amount of oil, gas and water being produced by individual wells is essential. The production revenue for each well is determined from measured flow rates. Measurement of well production can be achieved by using multiphase flow meters on individual wells. However, the use of such metering technique is not always reliable or economical. As an alternative technique to monitoring individual well performance in real-time, multiphase flow simulators together with pressure and temperature sensors located at different locations in the production systems have been recently deployed to estimate individual well flow rates. In the oil and gas industry, this technique has been called Virtual Flow Metering (VFM). In this study, the implementation and performance of commercially available multiphase flow simulators are evaluated using actual field production data. Field measurements from sensors are used which have been installed in various points of the productions system such as in the wellbore bottomhole and wellhead are used. This study is consisted of two parts: i) evaluation of the performance of virtual flow meters (flow models) with actual field data, and ii) evaluate the performance of VFM in different application scenarios such as flow metering backup and well production allocation. The model results are compared to actual flow rates to evaluate the effect of using different number of measuring points of pressure , temperature, and the effect of fluid properties. Although, the VFMs are easy to install, cheap and have low-cost maintenance, they have not been accepted as a replacement to MPFMs so far. This study will also investigate the combination of VFMs and MPFMs as a potential solution for the common problem of MPFMs malfunction and need of frequent calibration due flow assurance problems (such as scale deposition, and significant variations in multiphase flow behavior).

This study examines the role of crude oils surface active compounds (SAC) in determining the reservoir wettability. Wettability describes the relative preference of a reservoir rock for oil or water. Wettability influences the distribution of fluids in a reservoir and the efficiency of oil recovery methods. Unfortunately, the chemical mechanisms controlling wettability in individual reservoirs remain hazy. Wettability is conditional and is influenced by rock mineralogy, fluid chemistry, and temperature. An extensive experimental study was executed to understand the impact of naturally-occurring SACs typically found in crude oil, on the wettability of sandstone and carbonate rocks over a range of salinities and temperatures. To isolate the effects of individual SACs, this project used model oil mixtures of pure decane and SACs to represent the oleic phase. The four groups of SAC studied are: aromatic, oxygen-bearing, sulfur-bearing, and nitrogen-bearing SACs. Due to the large number of experiments in this study, standard wettability measurement methods were not used due to the time and expense it takes to run a single experiment. To overcome this barrier, the modified flotation technique (MFT) was developed. This wettability measurement method is fast reliable, and can serve both as a screening tool and provide quantitative results. In the quest to determine why low salinity waterflooding is successful in increasing oil recovery in some reservoirs and not in others, this study found that it is crucial to accurately characterize crude oil, brine, and reservoir rock material. This allows one to effectively engineer injection water chemistry which would favorably alter wettability, and maximize oil recovery. The overall effect toward either oil-wet or water-wet conditions was observed to depend more on brine salinity than temperature. As salinity was decreased nitrogen SACs, non-acidic sulfur SACs, and the short chained oxygen SAC shifted the wettability of the carbonate rocks towards water-wet conditions. Long chained acids SACs, acidic sulfur SACs, and aromatics shifted the wettability of carbonates towards oil-wet conditions as brine salinity was decreased. This difference in SACs reaction to salinity was proposed as one of the reasons why low salinity waterflooding is successful in some reservoirs and not in others.

Hydraulic fracturing is recognized as the primary technique to achieve economic oil and gas production from low permeability reservoirs like shale and tight-sand formations. One of the main challenges facing the oil and gas industry is maintaining the proppant functionality in the subsurface where replacement of proppant is only possible by expensive refracturing operations. Proppant crushing and proppant embedment have posed challenges for sustainable production from stimulated wells especially in soft and deep formations like Haynesville Shales. Experimental measurements show the strong impact of proppant stress and proppant embedment on reducing fracture conductivity. In this work, we introduce a new class of smart Expandable Proppants (EP) to remotely control the expanding force and maintain the functionality of injected placed proppants. Our smart proppants are made out of thermoset shape memory polymers which are activated by formations in situ temperature to effectively maintain or even increase fractures width. A fully coupled CFD-DEM model is developed to study the effectiveness of expandable proppants and evaluate fracture conductivity enhancement via different combination and distribution of EP. In addition, a series of experiments were conducted in a modified API conductivity cell to measure the increase in fracture conductivity. Different conditions of temperature, confining stress, proppant size and concentrations are carried out to verify the optimum conditions.

In this endeavor we attempt to better understand gas transport in shale gas reservoirs, specifically the impact and effects of different physical phenomena. We start by documenting the nature of the reservoirs and the need for accurate modeling of various physical phenomena in multiple interconnected continua. The physical phenomena of interest include non-linear Forchheimer flow, Knudsen diffusion in the form of slip "Klinkenberg" flow and adsorption/desorption. The numerical methods used in the reservoir simulator are also introduced, along with a derivation of the main equations used. Various verification and validation results are compared against manufactured and analytical solutions and finally advanced features including mesh adaptivity and multi-block support are showcased. Several detailed parameter survey studies are conducted with realistic and exaggerated field values to identify the need for advanced physics models based on deviation from Darcy models. Recommendations as to the applicability of each model are presented along with suggested best practices of when to apply these models in real simulations. A redefinition of the SRV is proposed, based on the need to apply a non-Darcy flow model. This new definition would highlight the need for advanced (and costly) non-linear flow ow models near the wells and hydraulic fractures. The judicious application of computationally intensive physical models in the SRV and lower fidelity models further away is presented as an efficient alternative to large scale high fidelity simulations.

<p> Rock geo-mechanical properties are important in petroleum engineering. The determination of reservoir&rsquo;s mechanical properties is critical to reduce drilling risk and maximizing well and reservoir productivity. Rock geo-mechanical properties vary not only with rock types, but also with measurement method, samples geometry (sample size and length to diameter ratio), and other factors. Because rocks are heterogeneous media, sample geometry can significantly affect measured rock mechanical properties, including unconfined and confined compressive strength, Young&rsquo;s Modulus, and Poisson&rsquo;s ratio. In this study, uniaxial compressive tests were conducted on 31 different dimensions of Berea sandstone samples to study the geometry effects on rock geo-mechanical properties. The objective of this research is to provide a fundamental understanding of the geometry effects. Correlations equations were established and standardizing factors were generated to minimize the geometry effects and get more reliable rock mechanical properties. Failure mode of the tested samples was also studied in this work.</p>

<p> Production of natural gas from unconventional gas-hydrate reservoirs faces kinds of challenges and uncertainties. One of the main and most common problems in gas-hydrates drilling is the dissociated gas from gas hydrates with decrease of pressure, increase of temperature, or combination of them. A reliable method that can be applied to predict the temperature profile of fluid during circulating in the drilling pipe and the annulus is needed. An analytical model was developed in this study for predicting temperature profiles in drilling gas-hydrate deposits. A case study is provided and indicates a good consistency between model-implications and field observations. According to the sensitivity analyses, the temperature profile of fluid in the drill pipe can be affected by the thickness of drill pipe, density and heat capacity of drill mud, pumping rate of drill mud, geo-thermal gradient, and the surface geo-temperature. The bottom hole temperature is dominated by the temperature and flow rate of the injected drilling fluid, thermal conductivity of cement, heat capacity and density of drill mud, geo-thermal gradient and geothermal temperature at surface, thickness of drill pipe, and cement sheath. Higher geothermal gradient and surface geothermal temperature can lead to a higher temperature profile of fluid in the annulus. The Joule-Thomason cooling effect below the drill bit nozzles will rapidly diminish in a short interval above the bottom hole by the heating effect of geo-thermal gradient. The rate of penetration of drill bit has negligible effect on the fluid temperature profile due to the low percentage of heat flow contributed by the drill cuttings. </p>