Dissertations / Theses on the topic 'Of Petroleum and Natural Gas Engineering'

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.

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 ^–1–10^–2 mD) and in the vertical direction (~10^–4 mD) are orders of magnitude higher than the matrix permeabilities of these shale sample (10^–5 to 10 ^–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.

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.

The limit of drilling ERD comes from the excessive friction between the drill string and borehole. This study investigates the potential of increasing the limit of horizontal displacement through optimization of drilling fluid and bottom hole assemblies. We conclude that lubricating bottom hole with water can significantly increase the maximum permissible WOB. This effect is more pronounced in drilling tight sands than shales with gas. Cooling the bottom hole with gas expansion after bit nozzles can greatly increase the maximum permissible WOB in drilling formations with geothermal temperatures above 200 °C. Three mathematical methods have been developed for calculating the limit of horizontal displacement in extended drilling with gas. The Rigorous Method is recommended because it gives conservative result. Among several factors affecting the ERD with gas, friction coefficient and the weight of pipe in the horizontal section are the two controlling factors. Adequate weight of BHA in the curve section should be used to overcome the friction.

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.

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.

Based on porosity, petrographic analysis and mineralogy measurements on the all the samples, the Barnett shale seem to exhibit the best reservoir quality.

A new mechanistic model is developed for computing flowing fluid temperature profiles in both conduits simultaneously for a continuous-flow gas-lift operation. The model assumes steady heat flow in the formation, as well as steady heat flow in the conduits. This work also presents a simplified algebraic solution to the analytic model, affording easy implementation in any existing program. An accurate fluid temperature computation should allow improved gas-lift design.

Comparisons of the Hasan model, Alves model, and the new model with data from the Thompson Well, O’Connor Well, and Luo Wei Well show that the temperature profile given by the new model has a better accuracy than that of other models.

A sensitivity analysis was conducted with the new model. The results indicate that mass flow rate of oil and the tubing overall heat transfer coefficient are the main factors that influence the temperature distribution inside the tubing and that the mass flow rate of oil is the main factor affecting temperature distribution in the annulus. The annulus overall heat transfer coefficient and tubing overall heat transfer coefficient are the next significant factors.

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.

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.

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.

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.

In shale gas development, the mechanical properties of shale are crucial in hydraulic fracture propagation, wellbore stability, and the productivity of a shale gas wells. In this dissertation, acoustic velocity tests, uniaxial compressive tests, and Brazilian tensile tests were conducted on Eagle Ford and Mancos shale to investigate gas shale mechanical properties, including dynamic mechanial properties and static mechanical properties (compressive and tensile mechanical properties). Water content, mineralogy, and anisotropic effects on shale mechanical properties were analyzed.

Ultrasonic velocity measurements were performed on Eagle Ford shale samples. Dynaimic elastic properties were determined according to the compressive- and shear-wave vleocities. The results showed that both P- and S-wave velocities increase as confining pressure increases. Horizontal elastic modulus, vertical elastic modulus, and shear modulus increase with increasing confining pressure. While horizontal and vertical Poisson’s ratio exhibited more or less invariant with confining pressure. Transverse isotropy is an appropriate model to characterize Eagle Ford gas shale. Elastic properties of Eagle Ford shale are direction-dependent. Horizontal Young’s modulus is higher than vertical Young’s modulus and horizontal Poisson’s ratio is higher than vertical Poisson’s ratio. Increasing water content reduce Young’s modulus and shear modulus significantly. Induced water can make the shale softer. Water increase Eagle Ford shale’s anisotropies. Both P- and S- wave velocities decrease with increasing of TOC and clay content. Dynamic Young’s modulus, shear modulus, and bulk modulus vary inversely with TOC and clay. Poisson’s ratio does not correlate with TOC or clay content for these test samples.

Static mechanical properties were investigated by conducting uniaxial compressive tests and Brazilian tensile tests on Eagle Ford and Mancos shale samples. A new method was developed to analyze tensile elastic behavior of materials. The imbibed water significantly reduces the uniaxial compressive strength. Young’s modulus of wet samples is lower for corresponding dry samples. The maximum Young’s modulus decrease is up to about 70%. The imbibed water makes the shale softer. Poisson’s ratio increase with water content. Bedding plane/laminations have a significant impact on Eagle Ford indirect tensile strength, but not on Mancos shale. The imbibed water significantly reduces tensile strength and tensile Young’s modulus, but increase tensile Poisson’s ratio. Low clay content in the Eagle Ford shale (around 6%) and high clay content in the Mancos (around 22%) might be the explanation for the overall lower tensile strength of the Mancos than Eagle Ford shale.

Static and dynamic elastic properties of Eagle Ford shale samples are compared. Static Young’s modululs is lower than dynamic Young’s modulus. There is no strong correlations between static and dynamic Poisson’s ratio observed for the tested samples. The relationship of compressive and tensile mechanical properties of Eagle Ford shale are investigated. Tensile Young’s modululs is 0.76 to 0.98 times lower than corresponding compressive Young’s modulus. There is either no strong correlations between tensile and compressive Poisson’s ratio observed for the tested samples.

Water weaken mechanism was analyzed. Three potentially major weakening mechanisms—chemical effects, water clay interaction, and capillary pressure increase—were discussed in detail.

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.

CO₂ flooding has proven to be an effective technique for enhanced oil recovery. However, the application of CO₂ flooding in the recovery process of asphaltenic crude systems is often avoided, as high asphaltene precipitation rates may occur. While the effects of asphaltene concetration and CO₂ injection pressure on asphaltene precipitation rate have been the focus of many studies, asphaltene precipitation rate is not a reliable factor to predict the magnitude of asphaltene-induced formation damage. Wettability alteration is only caused by the immobile asphaltene deposits on the rock surface. The enternmaint of flocs may occur at high fluid velocity. Morover, the effective permeability reduction is only caused by the flocs, which have become large enough to block the pore throats. The dissociation of the flocs may occur under certain flow conditions. In this study, a compositional reservoir simulation was conducted using Eclipse 300 to investigate the injection practice, which avoids asphaltene-induced formation damage during both immiscible and miscible CO₂ flooding in asphaltenic crude system. Without injection, at pressure above bubble point, slight precipitation occurred in the zone of the lowest pressure near the producing well. As pressure approached the bubble point, precipitation increased due to the change in the hydrocarbon composition, which suggested that the potential of asphaltene-induced formation damage is determined by the overall fluid composition. At very low pressure, precipitation decreased due to the increase in the density.

As CO₂ was injected below the minimum miscibility pressure, a slight precipitation occurred in the transition zone at the gas-oil interface due to the microscopic diffusion of the volatile hydrocarbon components caused by the local concentration gradients. The increase in CO₂ injection rate did not significantly increase the precipitation rate.

As CO₂ was injected at pressure above the minimum miscibility pressure, precipitation occurred throughout the entire reservoir due to the vaporizing drive miscibility process. While precipitation increased with the injection rate, further increase in the injection rate slightly decreased the deposition due to shear. The pressure drop in the water phase caused by the pore throat increased the local water velocity, resulting in a more effective removal of the clogging asphaltene material.

This thesis describes a new general purpose dynamic process simulator applied to a natural gas liquefaction plant. More specifically, the Multi Fluid Cascade Process (MFCP). MFCP is the “Statoil Linde LNG Technology Alliance” - a proprietary and patented process for LNG production. This utilizes plate fin and spiral wound heat exchangers, produced by Linde AG, and Nuovo Pignone’s centrifugal compressors. This LNG technology is now being implemented for the Hammerfest baseload LNG project, Snøhvit.

The simulator is based on first principle conservation laws for energy and mass, and a simplified quasi-steady state momentum equation. Unit models for the process equipment (tanks/pipes, separation tanks, valves, liquid expanders, pumps, compressors, heat exchangers, and PI controllers) are described using rigorous thermodynamics. Equilibrium is assumed for all unit models, and equilibrium and physical properties are predicted with the Swoave-Redlich-Kwong or the Peng-Robinson equation of state.

Two different model approaches are compared in this work. One approach conserves energy in an enthalpy state, and the other conserves internal energy, the HP formulation and UV formulation respectively. The HP formulation defines a dynamic state for the pressure, and splits the integration of the fast and slow dynamics. The pressure states and the algebraic flow relations are solved by a fully implicit Euler method, while the internal unit model equation is solved locally with tailormade integration routines. The UV formulation, utilizes an analytical Jacobian, and is integrated with both a 1-stage Rosenbrock and freeware BDF codes.

The UV formulation generates an analytical Jacobian from physical property partial differentials. These property differentials are calculated from a first order approximation of the equilibrium. The equilibrium equations are linearized in dynamic state variables to produce partial differentials of the internal flash variables.

The simulator is tested on a portable PC. The full MFCP LNG plant is simulated with a fixed time step of 1.0 seconds, for both the HP and UV formulations.

The HP formulation has 611 ODE states. The UV formulation uses the 1-stage Rosenbrock method integrating a system with 1025 ODE states. The case simulated is a set point step for the LNG temperature controller. The plant is simulated over 9000 seconds. The major process dynamics are sampled every second, and plotted. The average performance of both formulation is better that 7 times real time. The worst local performance of the UV formulation is 1.7 times faster than the HP formulation, but more than 6 times faster than real time. The HP and UV formulations gave significantly different dynamic predictions.

The BDF codes proved too slow for practical use on the MFCP configuration.

The dynamic simulators in industry today are typically using a HP formulation, with precalculated thermodynamic data stored in look-up tables. The simulations of the full LNG plant show that simulators, utilizing EOS equilibrium descriptions, soon will be able to compare with modern industry simulators.

In this study, several efficient and accurate mathematical models and numerical solutions to unconventional reservoir development problems are developed. The first is the three-dimensional embedded discrete fracture method (3D-EDFM), which is able to simulate fluid flow with multiple 3D hydraulic fractures with arbitrary strike and dip angles, shapes, curvatures, conductivities and connections. The second is a multi-porosity and multi-physics fluid flow model, which can capture gas flow behaviors in shales, which is complicated by highly heterogeneous and hierarchical rock structures (ranging from organic nanopores, inorganic nanopores, less permeable micro-fractures, more permeable macro-fractures to hydraulic fractures). The third is an iterative numerical approach combining the extended finite element method (X-FEM) and the embedded discrete fracture method (EDFM), which is developed for simulating the fluid-driven fracture propagation process in porous media.

Physical explanations and mathematical equations behind these mathematical models and numerical approaches are described in detail. Their advantages over alternative numerical methods are discussed. These numerical methods are incorporated into an in-house program. A series of synthetic but realistic cases are simulated. Simulated results reveal physical understandings qualitatively and match with available analytical solutions quantitatively. These novel mathematical models and computational solutions provide numerical approaches to understand complicated physical phenomena in developing unconventional reservoirs, thus they help in the better management of unconventional reservoirs.