Carbon dioxide injection has currently become a major gas injection process for improved oil recovery. Laboratory evaluations of gas-oil miscibility conditions play an important role in process design and economic success of field miscible gas injection projects. Hence, this study involves the measurement and modeling of fluid-fluid miscibility in multicomponent hydrocarbon systems. A promising new vanishing interfacial tension (VIT) experimental technique has been further explored to determine fluid-fluid miscibility. Interfacial tension measurements have been carried out in three different fluid systems of known phase behavior characteristics using pendent drop shape analysis and capillary rise techniques. The quantities of fluids in the feed mixture have been varied during the experiments to investigate the compositional dependence of fluid-fluid miscibility. The miscibility conditions determined from the VIT technique agreed well with the reported miscibilities for all the three standard fluid systems used. This confirmed the sound conceptual basis of VIT technique for accurate, quick and cost-effective determination of fluid-fluid miscibility. As the fluid phases approached equilibrium, interfacial tension was unaffected by gas-oil ratio in the feed, indicating the compositional path independence of miscibility. Interfacial tension was found to correlate well with solubility in multicomponent hydrocarbon systems. The experiments as well as the use of existing computational models (equations of state and Parachor) indicated the importance of counter-directional mass transfer effects (combined vaporizing and condensing mass transfer mechanims) in fluid-fluid miscibility determination. A new mechanistic Parachor model has been developed to model dynamic gas-oil miscibility and to determine the governing mass transfer mechanism responsible for miscibility development in multicomponent hydrocarbon systems. The proposed model has been validated to predict dynamic gas-oil miscibility in several crude oil-gas systems. This study has related various types of developed miscibility in gas injection field projects with gas-oil interfacial tension and identified the multitude of roles played by interfacial tension in fluid-fluid phase equilibria. Thus, the significant contributions of this study are further validation of a new measurement technique and development of a new computational model for gas-oil interfacial tension and miscibility determination, both of which will have an impact in the optimization of field miscible gas injection projects.

The ability of an abrasive assisted water jet to cut through rocks and metals has potential applications in the oilfield. However, the size of cutting nozzle has not allowed water jet to be used on commercial scale for drilling reservoir rocks down-hole. Inefficient momentum transfer to abrasive particles from pressurized water and lack of abrasive feed rate control in commercially available units has further discouraged the use of water jet in oil industry. Despite various technical difficulties, immense power of water jet cannot be neglected. Studies have shown that momentum transfer can be improved significantly, if abrasive particles are introduced upstream of the nozzle. Limited techniques are available where abrasives are first suspended in a fluid stream and are then introduced in high-pressure water stream upstream of the nozzle. However, control over abrasive feed rate was lacking in past studies. In this investigation, an experimental apparatus was assembled a polymer solution was injected upstream of the nozzle. Injection rate was controlled, by varying the rpm of the plunger pump. The apparatus was used to study the effect of Xanthan and Polyacrylamide on water jet coherency. It is shown that addition of polymer leads to a focused water jet for a longer distance before it starts disintegrating into a mist. Furthermore, there is an optimum concentration of polymer at which the jet stays focused for the longest distance.

Natural gas hydrates are thought to be the future hydrocarbon source of the energy hungry world. Tremendous amount of research has been done to investigate the feasibility of gas production from the hydrate formations. In this direction, three basic production methods, thermal stimulation, depressurization and thermodynamic inhibitor injection have been proposed to produce hydrocarbons off the hydrates. On the other hand, they present high potential risk of drilling hazards, such as severe gasification of drilling fluid, casing collapse due to increase in pressure after dissociation of hydrate zone, and instability of ocean floor, which may cause a platform failure. Scientists and engineers have done very valuable research to understand the phase behavior of hydrates and to prevent hydrate formation throughout the well system during drilling. Reliable hydrate inhibitors have been developed for drilling and production activities. Common practice for the drilling industry has been avoidance of hydrate formations by either abandoning the project or drilling expensive directional wells to reach the target zones for many years. The goal of this project was to quantify the significance of potential problems to allow operational methods and well design to be adopted to minimize the impact of hydrate zone on drilling operations for Eastern Black Sea Offshore Exploration Project. Investigating the existing hydrate dissociation models and adopting a model to predict the amount of dissociated gas was the first step. Further steps were investigation of temperature distribution throughout the well using a thermal simulator and prediction of heat influx from the drilling fluid into the hydrate zone. In this study, hydrate dissociation mechanisms are described. Drilling and production hazards associated with dissociation are stated. For the investigation of hydrate stability/instability, well bore temperature distribution in the near well bore is determined. Hydrate dissociation rate is calculated, and results are evaluated for further changes in drilling program and well design parameters. Results obtained from the dissociation calculations were applied to a set of data from two wells drilled by ARCO/Turkish Petroleum Corporation Joint Venture in Western Black Sea, and were used to design the prospective Eastern Black Sea Offshore Exploration wells.

Feasibility of drilling with supercritical carbon dioxide to serve the needs of deep underbalanced drilling operations has been analyzed. A case study involving underbalanced drilling to access a depleted gas reservoir is used to illustrate the need for such a research. For this well, nitrogen was initially considered as the drilling fluid. Dry nitrogen, due to its low density, was unable to generate sufficient torque in the downhole motor. The mixture of nitrogen and water, stabilized as foam generated sufficient torque but made it difficult to maintain underbalanced conditions. This diminished the intended benefit of using nitrogen as the drilling fluid. CO₂ is expected to be supercritical at downhole pressure and temperature conditions, with density similar to that of a liquid and viscosity comparable to a gas. A computational model was developed to calculate the variation of density and viscosity in the tubing and the annulus with pressure, temperature and depth. A circulation model was developed to calculate the frictional pressure losses in the tubing and the annulus, and important parameters such as the jet impact force and the cuttings transport ratio. An attempt was made to model the temperatures in the well using an analytical model. Corrosion aspects of a CO₂ based drilling system are critical and were addressed in this study. The results show that the unique properties of CO₂, which is supercritical in the tubing and changes to vapor phase in the annulus, are advantageous in its role as a drilling fluid. It has the necessary density in the tubing to turn the downhole motor and the necessary density and viscosity to maintain underbalanced conditions in the annulus. The role of a surface choke is crucial in controlling the annular pressures for this system. A carefully designed corrosion control program is essential for such a system. Results of this study may also be important for understanding the flow behavior of CO₂ in CO₂ sequestration and CO₂ based enhanced oil recovery operations.

Currently, the Water-Alternating-Gas (WAG) process is the most widely practiced horizontal mode gas injection process in the industry. Although this process is conceptually sound, it has resulted in low (5 10%) oil field recoveries. Conversely, the gravity stable mode of gas injection has carved its niche as one of the most effective methods of gas injection EOR in the dipping reservoirs and pinnacle reefs. The Gas Assisted Gravity Drainage (GAGD) process is therefore being developed at LSU to extend these highly successful gravity stable applications to horizontal type reservoirs. The dissertation attempts to address six key questions: (i) do we continue to fix the problems of gravity segregation in the horizontal gas floods or find an effective alternative?, (ii) is there a happy-medium between single-slug and WAG processes that would outperform both?, (iii) what are the controlling multiphase mechanisms and fluid dynamics in gravity drainage processes?, (iv) what are the mechanistic issues relating to gravity drainage?, and (v) how can we model the novel GAGD process using traditional analytical and empirical theories and (vi) what are the roles of the classical displacement, versus drainage in the GAGD process? The original contributions of this work to the existing literature are summarized as: (i) first demonstration of the GAGD concept through high pressure experimentation, (ii) experimental demonstration of the superior oil recovery performance of the GAGD process in secondary (immiscible recovery range: 62.3% to 88.56% ROIP) and tertiary (immiscible recovery range: 47.3% to 78.9% ROIP) processes, in both miscible (avg. secondary and tertiary miscible recoveries: near 100% ROIP) and immiscible modes, and in varying wettability and rock types, (iii) experimental verification of the hypothesis that the GAGD process is largely immune to the deteriorating effects of reservoir heterogeneity and that the presence of vertical fractures possibly aid the GAGD oil recoveries, (iv) experimental demonstration of the possibility of premature gas breakthrough does not mean end of the GAGD flood, (v) preliminary mechanistic and dynamic differences between the drainage and displacement phenomenon have been identified and a new mechanism to characterize the GAGD process fluid mechanics has also been proposed.

The improvement or increase of oil recoverable from discovered reservoirs has always been a very important issue as this helps to meet ever growing energy demand. Several methods have been put forward as means of achieving this objective. Chemical flooding, using surfactants has been considered in enhanced oil recovery processes. Surfactants are used primarily to lower oil-water interfacial tension (IFT) and thus improve production. However, surfactants possess the ability to alter rock wettability and hence increase oil production. Previous investigations were performed at ambient conditions using stocktank oil. Extrapolation of the findings from the ambient conditions testing to reservoir conditions may be erroneous. Thus, reservoir condition investigations have been carried out using Yates live crude oils and Yates synthetic brine. Several coreflood experiments have been conducted at live reservoir conditions using two types of surfactants (anionic and nonionic) in varying concentrations. A core flood simulator based on JBN technique has been used to calculate oil-water relative permeabilities by history matching recovery and pressure drop measured during the corefloods. The simulated relative permeabilities have been used to infer wettability alteration based on Craigs rule of thumb to characterize wettability. The contact angle measurements, from previous investigations conducted at LSU, have been used to compare wettability alterations inferred from relative permeabilities. Furthermore, this study includes imbibition experiments as another means to infer wettability alterations by surfactants. Initial wettability has been established for the Yates field using the Amotts wettability index and changes in the wettability indices with varying surfactant concentration have also been measured. These changes have been interpreted to infer wettability alteration. The use of nonionic ethoxy alcohol surfactant at different concentrations with Yates live crude oil in corefloods experiments showed significantly higher oil recoveries indicating that the surfactant has altered wettability. The optimum surfactant concentration has been established at 1500 ppm. Other experiments conducted using the anionic ethoxy sulphate surfactant have not shown a favorable wettability alteration as Yates core was altered from weakly water-wet to weakly oil wet consequently lowering oil recoveries. Analysis of the experimental results in terms of capillary number for the live oil floods at reservoir conditions demonstrated the significance of including measured water-advancing contact angle in definition of the capillary number. The ambient imbibition tests and reservoir condition coreflow experiments conducted in this study have provided an insight into effect of surfactants on wettability alteration at both ambient and reservoir conditions using stocktank oil and live reservoir fluids and the improvement in oil recoveries as a result of wettability alteration.

The Gas-Assisted Gravity Drainage (GAGD) process was developed to take advantage of the natural segregation of injected gas from crude oil in the reservoir. It consists of placing a horizontal producer near the bottom of the reservoir and injecting gas using existing vertical wells. As the injected gas rises to the top to form a gas cap, oil and water drain down to the horizontal producer. Earlier experimental work using a physical model by Sharma had demonstrated the effectiveness of the GAGD process in improving the oil recovery when applied in water-wet porous media. The current research is an extension of that work and is focused on evaluating the effect of the wettability of the porous medium and the presence of a vertical fracture on the GAGD performance. The effect of the injection strategy (secondary and tertiary mode) on the oil recovery was also evaluated in the experiments. In the physical model experiments a Hele-Shaw type model was used (dimensions: 13 7/8 by 5/16 by 1) along with glass beads and silica sand as the porous media. Silanization with an organosilane (dimethydichlorosilane) was used to alter the wettability of the glass beads from water-wet to oil-wet. The experiments showed a significant improvement of the oil recovery in the oil-wet experiments versus the water-wet runs, both in the secondary and the tertiary modes. The fracture simulation experiments have also shown an increase in the effectiveness of the GAGD process.

The Gas Assisted Gravity Drainage (GAGD) process, currently being developed at LSU, is designed to take advantage of gravity to allow vertical segregation between the injected gas and reservoir crud oil due to their density differences. GAGD is recommended for use with CO2 gas. CO2 dissolves in oil and causes both swelling and viscosity reduction of oil. The GAGD process uses the existing vertical wells for CO2 gas injection, and a horizontal well near the bottom of the payzone for oil production. GAGD, as an EOR process, is not restricted to tertiary oil recovery only. In this research study, a visual glass model has been used to visually discern the mechanisms operative in the GAGD process. The model was also designed to fit different vertical well configurations. The model experiments have proven that GAGD is a viable process for secondary and tertiary oil recovery. Oil recovery in the immiscible secondary mode was as high as 83% IOIP and the oil recovery in the immiscible tertiary mode was 54% ROIP. The model has also shown that the gas injection depth may not have an influence on oil recovery as long as there is vertical communication between reservoir layers. Four different injection depths resulted in oil recovery values between 71% IOIP and 76% IOIP. The visual model experiments have also demonstrated that GAGD is applicable to naturally fractured reservoirs. The oil recovery in the fractured porous media was as high as 76% IOIP, which was higher than the average in homogenous porous media (73% IOIP). Additionally, the GAGD process was found to be viable for higher viscosity oils as well, where secondary immiscible oil recovery was 64% IOIP. Miscible secondary injection was performed by using naphtha as the oil phase and decane as the miscible gas phase to simulate the miscible GAGD process. The visual model has resulted in a microscopic sweep efficiency close to 100% in the miscible GAGD process. The visual model experiments have demonstrated three possible mechanisms responsible for high oil recoveries: Darcy-type displacement until gas breakthrough, gravity drainage after breakthrough, and film drainage in the gas invaded regions.

Minimum miscibility pressure (MMP) is an important optimization parameter for an enhanced oil recovery process involving Carbon Dioxide or hydrocarbon gas injection. Therefore an accurate experimental measurement is required to determine the MMP. The MMP for a gas-oil system is directly related to the interfacial tension between the injected gas and the reservoir crude oil. When CO2 gas contacts the reservoir oil at reservoir temperature, the interfacial tension between the fluid-fluid phases reduces as the miscibility is approached and the interface between the fluid-fluid phases eventually disappears at miscibility i.e. the interfacial tension becomes zero. Hence, a pressure condition of zero interfacial tension at reservoir temperature is the minimum miscibility pressure for a CO2-reservoir crude oil system. The Vanishing Interfacial Technique (VIT) technique to determine MMP is based on this principle. Therefore, this research project involves the measurement of gas-oil interfacial tensions for a CO2-live reservoir oil system at reservoir conditions using the pendant drop and the capillary rise techniques to determine the minimum miscibility pressure through the VIT technique. Gas-oil interfacial tension, being a property of the interface between crude oil and gas, is strongly affected by the compositional changes induced by the counter-directional mass transfer (vaporizing, condensing or a combination of the two) of the various components taking place between the CO2 and reservoir oil. This study hence investigates the mass transfer mechanisms involved in these dynamic gas-oil interactions responsible for miscibility development by performing detailed compositional analyses, and density measurements. All the measurements were carried out at different ratios of fluid phases in the feed mixture (both molar and volumetric) for various pressures at the reservoir temperature in order to also study the effects of the initial feed composition on IFT and the phase compositions. This study has experimentally demonstrated that the gas-oil interfacial tension measured at varying feed compositions (i.e., initial gas-oil molar and gas-oil volume ratios) at reservoir temperature, although showing different relationships with pressure, converged to the same endpoint of zero-interfacial tension or similar minimum miscibility pressures. The effect of gas-oil molar ratios and gas- oil volume ratios on the compositions of the equilibrium phases for this CO2-reservoir fluid system proved that the mechanism involved in the mass transfer of hydrocarbon components between the fluid-fluid phases was a condensing gas drive mechanism. This study has demonstrated that the MMP determined from the VIT technique is independent of the compositional path followed by the fluids during their continuous interaction prior to attaining mass transfer equilibrium.

Managed pressure drilling is an innovative technique to precisely manage wellbore pressure. It is particularly applicable for reducing the risk of a kick or lost returns when drilling with a narrow window between pore pressure and fracture pressure. The constant bottomhole pressure method of managed pressure drilling uses annular frictional pressure and choke pressure in addition to mud hydrostatic pressure to achieve precise wellbore pressure control. This project investigated alternative initial responses to kicks to determine which would be most effective and reliable under different well scenarios when applying the constant bottomhole pressure method of managed pressure drilling. Three different initial responses to a kick, 'shut-in the well,' 'apply back pressure' and 'increase mud pump rate' were studied using an interactive transient multiphase flow simulator. The kick scenarios were varied by changing the hole size, type of kick fluid, initial kick volume, pressure differential at the kick zone, and fracture injectivity index. No single best response was identified for the kick scenarios that were studied. Nevertheless, some conclusions were reached. The validity of these conclusions may be limited to the range of scenarios studied. 'Increasing mud pump rate' is advantageous when it increases bottomhole pressure enough to stop formation flow because it results in the minimum casing and shoe pressures. Therefore, it should minimize the risk of lost returns or surface equipment failure. However, it is unlikely to be successful in large hole sizes. The 'apply back pressure' response has a similar but smaller advantage versus the 'shut-in' option because circulation creates friction in the annulus. However, in cases where lost returns occurred, no reliable way of identifying the loss of returns and avoiding unintentional formation flow to the surface was defined. The 'shut-in' reaction generally results in the highest casing and casing shoe pressures. Therefore, it may be most likely to cause loss of returns before stopping formation flow and consequently causing an underground transfer with continuous influx. Nevertheless, it is probably the least likely to unintentionally allow formation fluid flow to the surface or to cause loss of significant mud volume downhole.