The interest for developing geopressured-geothermal reservoirs along the US Gulf Coast is increasing for securing energy needs and reducing global warming. Identifying the most attractive candidate reservoirs for geothermal energy production requires quick and simple models. Analytical models are not always available and simulating each case individually is expensive. The use of scaling and statistical modeling is one approach to translate the output of a simulator into quick models with general applicability at all scales. The developed models can quickly estimate temperature and thermal energy recovery from the geopressured-geothermal reservoirs. These models can screen large databases of reservoirs to select the most attractive ones for geothermal energy production. This study presents two different designs for extracting energy from geopressured-geothermal reservoirs: Regular line drive and Zero Mass Withdrawal (ZMW). First, the governing partial differential equations describing each design are derived from the fundamental equations. Inspectional analysis on the partial differential equations of each design provides the most succinct and meaningful form of the dimensionless numbers for scaling the designs. The dimensionless numbers are tested and verified by selecting models with identical dimensionless numbers but different dimensional parameters. For creating the response models, statistics is used to find the important dimensionless numbers for predicting the response systematically. A procedure is used to compare all possible models and select the best one. These simplified final models are then presented and the performance of the simplified models is assessed using testing runs. Applications of these models are presented. To test the response models, two field cases from southern Louisiana are evaluated: the Gueydan Dome reservoir and the Sweet Lake reservoir. The Gueydan Dome reservoir (Vermilion parish, LA) is investigated using an optimization algorithm and it is concluded that the temperature map should be used for pre-development heat extraction assessments. The Sweet Lake reservoir (Cameron parish, LA) is studied using this conclusion.

Unlike the Continuous Gas Injection (CGI) and Water-Alternative Gas (WAG), the Gas Assisted Gravity Drainage (GAGD) process takes advantage of the natural segregation of reservoir fluids to provide gravity-stable oil displacement. The gas is injected through existing vertical wells to formulate a gas cap to allow oil and water drain down to the horizontal producer (s). Therefore, the GAGD process was implemented through immiscible and miscible injection modes to improve oil recovery in a sector of the main pay/upper sandstone member in the South Rumaila oil field, located in Iraq. A high-resolution geostatistical reservoir characterization model was constructed to model the lithofacies and petrophysical properties in order to provide the most realistic geological environment for the GAGD process evaluation. After upscaling the geostatistical model, a compositional reservoir simulation was built to evaluate the GAGD process and test its effectiveness to improve oil recovery. Next, sensitivity analysis was performed to determine the most influential reservoir parameters that impact the GAGD process. With no effect of reservoir porosity, it was also investigated that reservoir permeability and anisotropy ratio have the most impact on the reservoir flow response through the GAGD process. Then, several GAGD optimization and uncertainty assessment approaches were conducted to determine the optimal future reservoir scenario of the largest improvement in oil recovery. These optimal cases include operational decision parameters, injection pressure, and cycling injection. It was concluded that the cycling GAGD process has better performance to improve oil recovery than the continuous injection mode. In addition, all the successive approaches of the optimization and uncertainty assessments led to in- crease oil production by more than 500 million barrels over the base-case GAGD process of default operational decision parameters. Finally, both heterogeneity and anisotropy effects have been identified by showing a significant impact on the reservoir flow responses. Specifically, the effect of permeability anisotropy is higher than reservoir heterogeneity be cause the main concept of the GAGD process considers vertical fluid movements towards the horizontal producers. Consequently, the overall reservoir characterization, compositional simulation, and optimization of the immiscible GAGD process have shown its effectiveness to improve oil recovery in a real field-scale evaluation.

This project is sponsored by the Department of Energy of the United States and dedicated to development of electricity production from the low-enthalpy geothermal reservoirs. The prime interest are reservoirs that are characterized by low temperature of heat source located in deep saline aquifers with high permeable rock. Usually energy production from these resources are not economical by using a conventional binary power plant approach. The presented PhD work is a study of a new system that utilizes a single-well technology and working on supercritical power cycle (PC). The wellbore energy conversion system is operating with Zero Mass Withdrawal (ZMW) principle, which implies no geo-fluid pumping to the surface facility. This study introduces analyses of three main subsystems of the power unit. The heat extraction subsystem (HES) is located at the reservoir depth. The power generation subsystem (PGS) is represented by power cycle, and the heat rejection subsystem (HRS) contains an air driven condenser as the only part located on the surface. Several working fluids were examined. Based on the thermodynamic study the best working fluid choice is carbon dioxide. The project includes a simplified mathematical model derived from energy balance equations for each subsystem. Dimensionless analysis is performed in order to connect subsystems of different scales and show energy flow from the reservoir to the surface environment. The reservoir prototype is a hot saline aquifer located in Vermilion Parish, LA. The numerical model illustrates application of the ZMW method to the energy production from this reservoir. The maximum net power production is constrained by the power spent on a brine pump, which is a function of frictional losses in the downhole heat exchanger (DHE). The numerical investigation defines the optimal operating brine flow regime for the maximum net power production. One of the qualitative parameters of this design scheme is a thermal breakthrough time of injected cooled brine flowing toward the production side. This parameter is derived using potential flow theory application for several cases of flowing reservoirs, and various brine flow rates. The project contains an economic analysis based on determination of Levelized Cost of Electricity (LCOE). The results are in a good agreement with references and show competitive results for low-enthalpy reservoir exploration in terms of electric power production.

Past studies of surfactants for enhanced oil recovery by wettability improvement, have often categorized surfactants as either non-ionic, anionic or cationic. This research has been done in an attempt to study different surfactants under the same group in greater detail by varying their structures and to classify them on the basis of their abilities to alter reservoir wettability. Two different families of surfactants, both anionic, namely alkyl alkoxy sulfates and alkyl ether carboxylates, have been studied. Surfactants tested in each of these groups are tuned individually by the level of hydrophobicity that they offer by varying the nature of the anionic head group and the number of ethylene oxide and propylene oxide units that are present in their chemical structures. The experimental study is based on the Dual Drop Dual Crystal (DDDC) technique of dynamic contact angle measurement. Ten different surfactants, designed, manufactured and supplied by Sasol, were tested in a Yates oil Limestone Yates synthetic brine system at ambient conditions. The concentration levels of the surfactants were kept very low. This enabled substantially increased reaction time for the system to interact with the surfactant. It also helped isolate the effect of interfacial tension reduction and study the wettability alteration, if any, with clarity. Interfacial tension measurements as a factor of time were also conducted to determine its effect over extended periods of time, as opposed to effects of wettability alteration of the system. The surfactant structures were tested in order of decreasing hydrophobicity. Initial experimental results using reasonable concentration levels showed no varying effects between the individual surfactants. However upon considerable reduction of the surfactant concentration, each surfactant showed a variable effect on the oil droplet in terms of the measured dynamic contact angle measured as well as a factor of time. The dimensionless Bond numbers calculated for these surfactants helped quantify the rock fluids interactions by taking into consideration both possible wettability alteration as well as the reduced interfacial tension. It was found that no two extremes of a surfactant in terms of hydrophobicity or hydrophilicity were ideal for the system. The challenge of trying to classify surfactants that are so similar in structure also made way for an alteration in the way results obtained from the DDDC technique are conventionally interpreted. Surfactants have always been a popular choice in the field of enhanced oil recovery. However, no systematic means of classification yet exists that links the structure of a surfactant to its ability to alter reservoir wettability, especially when trying to classify surfactants that all belong to one singular family. This study is a step forward in that direction, to try and create a means of quantifying the effect that a particular structural variance could have on the potential recovery from a reservoir via altered wettability.

<p> Natural gas and oil exploration and production from shale formations have gained a great momentum in many regions in the past five years. Producing hydrocarbons from shale is challenging because of low productivity of wells. Optimal design of transverse fractures is a key to achieving successful well completion and field economics. The minimum fracture spacing and the fracture propagation trajectory are the determinant for the successful transverse fracture optimization. Various states of anisotropic stress have been applied to the simulated models with assigning criteria for fracture initiation and propagation. One of the factors that need to be addressed is the trajectory of a fracture in the presence of varying stress fields. The injection of treatment fluid in the initial crack exerts pressure from inside and the stress field around the fracture tip controls fracture extension direction. The new analytical model presented in this paper is used to quickly predict hydraulic fracture propagation trajectory based on completion situation. The fracture geometry obtained by this model is a reliable resource for designing the multi-stage hydraulic fracture spacing in shale gas formation and evaluating hydraulic fracturing horizontal well completion. Result of the analytical method has been verified by a Finite Element Method for a typical fracturing condition in a shale gas formation.</p>

<p> The importance of cement integrity in the downhole well cannot be over looked. Cement designed for a particular well may not work for another well. As a result, there is a need to design well cement based on appropriate well conditions in order to achieve good integrity during the life time of the well. This research focused on micro-annulus and crack problems associated with downhole well cements. Waste tires have contributed to environmental problems. </p><p> Waste tires can be crushed into small particles and used for construction purposes. This is seen as a promising avenue to get rid of the waste tires. This research focused on the possibility of adding tire rubber particles to well cement to reduce the effect of micro-annuli and cracks in well cement. Tire rubber particles of 4 different sizes were used in this research, which was then divided into two parts. The first part dealt with rheology and compressive strength of concretes. These parameters were used to select cement designs with optimum value for subsequent tests. The other part included permeability and creep tests. Permeability measured the amount of water the concrete materials could yield while the creep test measured strain developed when concrete specimen was subjected to a constant stress for 30 minutes and the amount of strain recovered when the concrete specimen was unloaded for another 30 minutes. Creep compliance was done to measure the rate at which strain was developing, which is a function of time under constant stress. </p><p> Concrete containing the largest rubber particle size had good amount of strain recovery after unloading while concrete samples containing the smallest rubber particle size had the lowest amount of strain recovery. </p>

Wellbore stability analysis acts an important role in the drilling design to avoid pipe-stuck, lost circulation and the other instability-induced problems. However, the conventional linear elastic model used by the industry is too conservative in predicting the mud weight window. This project is aimed at improving the accuracy of wellbore stability analysis. An elastoplastic model with Drucker-Prager yield criterion featured by strain hardening is proposed to characterize the rock behavior. Object-oriented finite element analysis simulator, NSMOOM, is programmed in MATLAB. The simulator is verified with the analytical solution in the elastic domain and with the commercial software ABAQUS in the elastoplastic domain. Upon the good verification results, the code is applied to an under-balanced-drilling case. For the case study, a good match is shown between the prediction of the proposed elastoplastic model and the actual wellbore response. On the other hand, no available mud weight window for under-balanced-drilling can be calculated by the pure elastic model. In conclusion, the proposed model provides a more realistic tool to predict wellbore stability.

This thesis presents an improved model for gas-liquid two-phase flow in churn and annular flow regimes for small- and large-diameter in vertical and near-vertical pipes. This new model assumes that a net liquid film moves upward along the pipe wall and gas phase moves upward, occupying the majority of the central part of the pipes, and forming a gas core, in both flow regimes. The model is validated using field and laboratory experimental data from several different studies from the literature, in terms of pressure along the wellbore or bottomhole pressure for field conditions (for high-pressure flows in long pipes, and using hydrocarbons fluids), and pressure-gradient and liquid holdup for experimental laboratory data, for pipe diameters ranging from 0.0318 to 0.279 m (1.2520 to 11 in). The proposed model presents an overall better performance when compared to several other multiphase flow models widely used in the oil and gas industry. This model is also tested in the application of prediction of liquid loading in gas wells. Liquid loading is generally associated with a reduction of ultimate recovery of gas wells. Liquid loading inception is simulated using nodal analysis technique. This study suggests that liquid loading initiates when the Inflow Performance Relationship (IPR) curve is tangent to the TPR curve. This study also proposes a new concept of a modified Tubing Performance Relationship (TPR) curve in order to predict the time liquid loading initiates and when the gas well will stop flowing after reaching this condition. Field data is used for validation of this approach. The use of conventional models shows a significant mismatch predicting the inception of liquid loading, while the use of the tangent concept reduces this mismatch significantly.

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.