Proper selection of drilling fluids plays a major role in determining the efficient completion of any drilling operation. With the increasing number of ultra-deep offshore wells being drilled and ever stringent environmental and safety regulations coming into effect, it becomes necessary to examine and understand the behavior of water based drilling fluids - which are cheaper and less polluting than their oil based counterpart - under extreme temperature and pressure conditions. In most of the existing literature, the testing procedure is simple - increase the temperature of the fluid in steps and record rheological properties at each step. A major drawback of this testing procedure is that it does not represent the continuous temperature change that occurs in a drilling fluid as it is circulated through the well bore. To have a better understanding of fluid behavior under such temperature variation, a continuous test procedure was devised in which the temperature of the drilling fluid was continuously increased to a pre-determined maximum value while monitoring one rheological parameter. The results of such tests may then be used to plan fluid treatment schedules. The experiments were conducted on a Chandler 7600 XHPHT viscometer and they seem to indicate specific temperature ranges above which the properties of the drilling fluid deteriorate. Different fluid compositions and drilling fluids in use in the field were tested and the results are discussed in detail.

In efforts to render the safest, fastest, and most cost efficient drilling program for a high temperature and high pressure (HT/HP) well the maximization of drilling operational efficiencies is key. Designing an adequate, HT/HP well specific, drilling fluid is of most importance and a technological challenge that can greatly affect the outcome of the overall operational efficiency. It is necessary to have a sound fundamental understanding of the behavior that water-based muds (WBM) exhibit when exposed to HT/HP conditions. Therefore, in order to adequately design and treat a WBM for a HT/HP well specific drilling program, it is essential that the mud be evaluated at HT/HP conditions. Currently, industry standard techniques used to evaluate WBM characteristics involve aging the fluid sample to a predetermined temperature, based on the anticipated bottom hole temperature (BHT), either statically or dynamically, for a predetermined length, then cooling and mixing the fluid and measuring its rheological properties at a significantly lower temperature. This, along with the fact that the fluid is not subjected to the anticipated bottom hole pressure (BHP) during or after the aging process, brings to question if the properties recorded are those that are truly experienced down-hole. Furthermore, these testing methods do not allow the user to effectively monitor the changes during the aging process. The research in this thesis is focused on evaluating a high performance WBM and the current test procedures used to evaluate their validity. Experimental static and dynamic aging tests were developed for comparative analysis as well to offer a more accurate and precise method to evaluate the effects experienced by WBM when subjected to HT/HP conditions. The experimental tests developed enable the user to monitor and evaluate, in real-time, the rheological changes that occur during the aging of a WBM while being subjected to true BHT and BHP. Detailed standard and experimental aging tests were conducted and suggest that the standard industry tests offer false rheological results with respect to true BHT and BHP. Furthermore, the experimental aging tests show that high pressure has a significant effect on the rheological properties of the WBM at elevated temperatures.

La situation durable de volatilité des prix du pétrole est considérée à la fois comme une menace et un défi par l'industrie pétrolière. Au cours de cette crise, les compagnies pétrolières ont l’opportunité de se recentrer sur la recherche de solutions de production rentables, ce qui implique souvent l’apport des nouvelles technologies, en plus de l'amélioration des processus.Ce travail présente une avancée pour la synthèse d’une nouvelle génération de fluides de forage pétrolier sans surfactants/émulsifiants pour des applications dans le forage des puits profonds et ultra profonds. Cette nouvelle génération repose sur l’introduction des émulsions de Pickering dans la formulation des fluides de forage. Ces dernières sont des émulsions stabilisées uniquement par des particules solides (dans ce cas des particules de silice). Différents types de nano particules de silice de différentes hydrophobicités ont été utilisées pour stabiliser des fluides de forage de types huile-dans-eau et eau-dans-huile. Ces fluides ont été conçus pour être utilisés dans des conditions hostiles de température et de pression. Par conséquent, une caractérisation expérimentale de leur stabilité ainsi que de leurs propriétés rhéologiques sous ces conditions extrêmes étaient nécessaires. Au cours de ce travail, les profils rhéologiques de ces fluides reflétant leurs capacités de nettoyage du puits, leur coulabilité ainsi que leurs capacités à transporter les débris jusqu'à la surface, ont été établis. D’autre part, la stabilité électrique des émulsions ainsi que leur morphologie (distribution de taille des gouttelettes) ont été étudiées et une comparaison avec celles stabilisées par des agents tensioactifs a été établie. Les fluides ont été exposés à un processus de vieillissement qui permet d’étudier l'effet de l'environnement du réservoir hostile sur la stabilité et la rhéologie des nouveaux fluides préparés. Ces fluides de haute qualité se sont révélés très fiables, offrant une grande stabilité et une capacité à résister à des conditions extrêmes de réservoir. Ils représentent une nouvelle génération de fluides de forage ouvrant la voie à une exploitation optimisée de réservoirs profonds et ultra profonds. / This enduring situation of volatile oil prices has been seen as a decline and a challenge at the same time for the oil and gas industry. It is during this slump that the oil and gas companies own the opportunity to focus on cost-effective production solutions, which very often means bringing new technologies and further improving processes.This work presents a novel frontier of surfactant-free drilling and completion fluids for deep and ultra-deep wells. This new generation of drilling fluids is based on the principle of Pickering emulsions (emulsions stabilized solely by solid nano particles). Hydrophobic and hydrophilic silica nano particles were used to stabilize Oil-Based Mud and Water-Based Mud. These fluids were designed to be used under hostile conditions of temperature and pressure. Therefore, a concrete characterization of their stability as well as their rheological properties under HTHP conditions was mandatory. Rheological profiles reflecting the flowability, hole cleaning capacity as well as cutting transport ability of the fluids were established. On the other hand, the electrical stability as well as the morphology (Droplet Size Distribution) of the emulsions were studied and compared with surfactant-stabilized drilling fluids. The fluids were submitted to an aging process allowing one to study the effect of hostile reservoir environment on the stability and rheology of the new fluids prepared.These high quality fluids were seen very reliable offering high stability as well as high capacity to withstand extreme reservoir conditions giving rise to a new generation of drilling fluids allowing breaking the frontiers of deep and ultra-deep reservoirs.

Knowledge of thermodynamic fluid properties, such as density and phase behavior, is important for the design, operation, and safety of several processes including drilling, extraction, transportation, and separation that are required in the petroleum. The knowledge is even more critical at extreme temperature and pressure conditions as the search for more crude oil reserves lead to harsher conditions. Currently, there is dearth of experimental data at these conditions and as such, the predictive capability of the existing modeling tools are unproven. The objective of this research is to develop a fundamental understanding of the impact of molecular architecture on fluid phase behavior at temperatures to 523 K (250 °C) and pressures to 275 MPa (40,000 psi). These high-temperature and high-pressure (HTHP) conditions are typical of operating conditions often encountered in petroleum exploration and recovery from ultra-deep wells that are encountered in the Gulf of Mexico. This PhD study focuses on the fluid phase behavior of a low molecular weight compound, two moderately high molecular weight compounds, three asymmetric binary mixtures of a light gas and a heavy hydrocarbon compound with varying molecular size. The compounds are selected to represent the family of saturated compounds found in typical crude oils. Furthermore, this study reports experimental data for two "dead" crude oil samples obtained from the Gulf of Mexico and their mixtures with methane from ambient to HTHP conditions. A variable-volume view cell coupled with a linear variable differential transformer is used to experimentally measure the high-pressure properties of these compounds and mixtures. The reported density data compare well to the limited available data in the literature with deviations that are less than 0.9%, which is the experimental uncertainty of the density data reported in this study. The phase behavior and density data obtained in this study are modeled using the Peng-Robinson (PR), the volume-translated (VT) PR, and the Perturbed-Chain Statistical Associating Fluid Theory (PC-SAFT) equations of state (EoS). The EoS pure component parameters, typically obtained from the open literature, are derived from fitting the particular EoS to, critical point, or to vapor pressure and saturated liquid density data, or to HTHP density data. For the density data reported here, the PREoS provided the worst predictions, while the VT-PREoS gives an improved performance as compared to the PREoS. However, the PC-SAFT EoS provided the best HTHP density predictions especially when using HTHP pure component parameters. The situation is however reversed in the modeling performance for the phase behavior data whereby the PC-SAFT EoS with HTHP parameters provided the worst vapor-liquid equilibria predictions. Better predictions are obtained with the PC-SAFT EoS when using parameters obtained from fit of the vapor pressure data and is comparable to the PREoS predictions. This reversal in performance is not surprising since the phase behavior data occur at moderately low pressures. The performance of the PC-SAFT EoS is extended to the experimental density data reported for the dead crude oil samples and their mixtures with methane. The PC-SAFT EoS with either set of pure component parameters yield similar predictions that are within 3% of the reported crude oil density data. However, when using the HTHP parameters, the PC-SAFT gives a good representation of the slope of experimental data, which is crucial in the calculation of second-derivative properties such has isothermal compressibility. The PC-SAFT EoS is also employed to model the crude oil HTHP density data for both the dead crude oils and their mixtures with methane using correlations for both the Low-P parameters and the HTHP parameters. The Low-P parameters are derived from fitting the PC-SAFT EoS to pure compound vapor pressure and saturated liquid density data, while the HTHP parameters are obtained from fitting the PC-SAFT EoS to pure compound HTHP liquid density data. Interestingly, the PC-SAFT EoS with the Low-P parameters provided better HTHP density predictions that are within 1.5% of the experimental data for the dead oils than the HTHP parameters that are within 2 to 4% of the data. Density predictions for the dead oil mixtures with methane are however comparable for both sets of parameters and are within 1% on average. However, the PC-SAFT EoS with HTHP parameters clearly provided better representation of the isothermal property, a derivative property obtained from density data, within 10% while predictions with the Low-P parameters can be as high as 37%. The successful completion of the thesis work expands the current knowledge base of fluid phase behavior at the extreme operating conditions encountered by engineers in the petroleum industries. Furthermore, the reported HTHP experimental data also provide a means to scientists and researchers for the development, improvement, and validation of equations with improved modeling performance.

Modern day oil & gas well costs are driven by drilling performance as time becomes the dominant capital expense source. The ability to lower drilling costs becomes paramount when tight economic margins and high uncertainties/risk exist. Penetration rate decreases drastically in ultra deep formations, and substantial time is spent drilling the deepest section of these wells. Therefore, significant cost savings may be obtained through an improvement in penetration rate in deep formations. This paper shows that in HTHP (High Temperature High Pressure) hard shale/sand environments that PDC (Polycrystalline Diamond Compact) bits paired with water based mud experience 88% improvement in penetration rate than those paired with oil based mud. With this improvement in drilling rate, well costs can be substantially reduced making future ultra-deep hydrocarbon accumulations economically producible. Also observed was a drastic decrease in penetration rate in PDC bits with oil base mud which led to the use of diamond impreg bits, as the water base with PDC still maintained respectable penetration rates. The conventional penetration rate controls are still applicable in this case, but there exists a fundamental difference between the rock/fluid interactions of each mud type. Bit type, operating conditions, formation characteristics, and bit hydraulics are shown to not be the dominant influencing factor of this performance trend. The water base fluids examined have higher filtrate rates than the oil base fluids. However, a consistent data set of increasing filtrate rate corresponding to increasing penetration rate cannot be derived. Therefore filtration characteristics remain as a possible and partial influencing factor behind this data. Future experimental research is needed to confirm or disprove this theory. At this time the actual cause of this behavior is unknown, however the trend has been established showing water base drilling fluids performance versus oil base in the HTHP/hard rock environment.

Oil companies need to evaluate the risk of annular fluid or gas migration if cement fails during the life of the well. Sustained casing pressure can lead to shutting in the wells to avoid health, safety, and environment (HSE) risks and government fines. To understand the long-term integrity of cement in high temperature and high pressure (HTHP) conditions and the mechanical properties that affect the ability of cements to seal fluids, this project used finite-element models (FEMs) to study the stress-causing phenomena. FEM analyses in ABAQUS version 6.11 were used to determine the potential of cement failure in oil wells. The model uses a 3D section of a well that can be used for different casing and formation types under different loading conditions. The model built in ABAQUS version 6.11 allows incorporating materials with nonlinear mechanical properties; it also uses FEM analysis to forecast fractures inside the cement under different loading scenarios like hydraulic fracture jobs or casing tests. The finite-element model included cases for cement cracking, cement debonding, and plastic deformation of the cement and rock that can generate loss of zonal isolation. Linear manner: set cements behave elastically until a failure criterion is reached, and then they can behave plastically. The FEM approach can reproduce stresses, strains, and volume changes in the material under different environmental HTHP conditions. Cemented wells have both tensile and compressive stresses that make some parts of the cement sheath experience fracture initiation, plastic deformation, or debonding. This dissertation provides a model that will help drillers design the set cement for long-term integrity in HPHT well conditions. The FEM predicts if the cement sheath can develop debonding, cracks or plastic deformations during the life of the well. The cement sheath needs to be designed for long-term zonal isolation to avoid interzonal communications, remedial costs and environmental problems related to cement seal. A CMS™-300 Automated Permeameter, a mechanical properties analyzer, HPHT cement consistometer, annular expansion molds, and tri-axial test equipment were used in this study to test cements for specific applications in three Colombian oil fields, including an oil field with in-situ combustion project.