<p> A 6012-foot Monterey Formation succession at Chico Martinez Creek, San Joaquin basin, is characterized at high spatial resolution by spectral gamma-ray data in 2- foot increments, 5-foot lithologic descriptions, and qualitative XRD and FTIR analysis. Based on these data, the 4 Monterey members&ndash;the Gould, Devilwater, McDonald and Antelope shales&ndash;are subdivided into 7 distinctive lithofacies. New paleomagnetic data, combined with industry-provided biostratigraphy establishes a chronostratigraphic framework and allows determination of linear sediment accumulation rates. Condensed sedimentation at the onset of McDonald deposition (~14 Ma) is also observed in correlative members in the Pismo, Santa Maria and Santa Barbara basins. This regional event is associated with eustatic regression from the Mid-Miocene highstand related to formation of the East Antarctic Ice Sheet and ongoing thermotectonic basin subsidence. A surge in linear sediment accumulation rates in the siliceous upper McDonald and Antelope (~10.4 Ma) is attributed to a regional increase in diatom productivity. </p>

A model consisting of the Hamaker-Lifshitz theory is used to calculate the spreading transition of alkanes at the water-gas interface. In the current work, the theory is extended to include effects of the temperature and pressure by estimating dielectric polarizability of the vapor and liquid as a function of density through the Clausius-Mosotti equation. The wetting transition temperature of alkane at the water-gas interface increases with increasing of carbon number. The theory is validated by measuring the contact angle of alkane at the water-gas interface by using an interference microscope. Spreading coefficients calculated from contact angles agree with the calculated values. The Hamaker constant calculation, measured contact angle, and measured spreading coefficient show that alkanes approach spreading as the NaCl concentration in water approaches saturation. The theory of this study is also used to predict the flow of sulfur containing sour natural gas in a reservoir, and the calculations are supported by the experimental results.

<p> Among the most important properties controlling the production from conventional oil and gas reservoirs is the distribution of porosity and permeability within the producing geologic formation. The geometry of the pore space within these reservoirs, and the permeability associated with this pore space geometry, impacts not only where production can occur and at what flow rates but can also have significant influence on many other rock properties. Zones of high matrix porosity can result in an isotropic response for certain reservoir properties whereas aligned porosity/permeability, such as open, natural fracture trends, have been shown to result in reservoirs being anisotropic in many properties.</p><p> The ability to identify zones within a subsurface reservoir where porosity/permeability is significantly higher and to characterize them according to their geometries would be of great significance when planning where new boreholes, particularly horizontal boreholes, should be drilled. The detection and characterization of these high porosity/permeability zones using their isotropic and anisotropic responses may be possible through the analysis of azimuthal (also referred to as azimuth-limited) 3D seismic volumes.</p><p> During this study the porosity/permeability systems of a carbonate, pinnacle reef within the northern Michigan Basin undergoing enhanced oil recovery were investigated using selected seismic attributes extracted from azimuthal 3D seismic volumes. Based on the response of these seismic attributes an interpretation of the geometry of the porosity/permeability system within the reef was made. This interpretation was supported by well data that had been obtained during the primary production phase of the field. Additionally, 4D seismic data, obtained as part of the CO₂ based EOR project, supported reservoir simulation results that were based on the porosity/permeability interpretation.</p>

<p> Detection of Morrow A sandstones is a major problem in the exploration of new fields and the characterization of existing fields because they are very thin and laterally discontinuous. The present research shows the advantages of S-wave data in detecting and characterizing the Morrow A sandstone. Full-waveform modeling is done to understand the sandstone signature in P-, PS- and S-wave gathers. The sandstone shows a distinct high-amplitude event in pure S-wave reflections as compared to the weaker P- and PS-wave events. Modeling also helps in understanding the effect of changing sandstone thickness, interbed multiples (generated by shallow high-velocity anhydrite layers) and sidelobe interference effect (due to Morrow shale) at the Morrow A level. </p><p> Multicomponent data need proper care while processing, especially the S-wave data which are aected by the near-surface complexity. Cross-spread geometry and 3D FK filtering are effective in removing the low-velocity noise trends. The S-wave data obtained after stripping the S-wave splitting in the overburden show improvement for imaging and reservoir property determination. Individual P- and S-wave attributes as well as their combinations have been analyzed to predict the A sandstone thickness. A multi-attribute map and collocated cokriging procedure is used to derive the seismic-guided isopach of the A sandstone. </p><p> Postle Field is undergoing CO₂ flooding and it is important to understand the characteristics of the reservoir for successful flood management. Density can play an important role in finding and monitoring high-quality reservoirs, and to predict reservoir porosity. prestack P- and S-wave AVO inversion and joint P- and S-wave inversion provide density estimates along with the P- and S-impedance for better characterization of the Morrow A sandstone. The research provides a detailed multicomponent processing, inversion and interpretation work flow for reservoir characterization, which can be used for exploration in other parts of the world as well.</p>

This project culminated in the development of a new flow method and device for measuring the water contents of high pressure gases. This new flow method uses both an electrical resistance sensor and/or a chemical desiccant method to measure the water contents of methane, ethane and methane + carbon dioxide and ethane + carbon dioxide gas mixtures from 3.4 MPa to 110 MPa over a temperature range from 310 to 477 K. The resulting measurements have reduced uncertainty in the binary experimental results to between 2 to 7 percent, and give ternary results with an uncertainty between 5 and 14 percent. The new experimental data are modeled using a hybrid method which combines the Peng-Robinson equation of state to calculate vapor phase fugacity coefficients with a highly accurate equation of state to calculate the fugacity of water. Gas solubilities in the aqueous phase are calculated using a Henry's law coefficient, while aqueous fugacities are calculated using the NIST/ASME equation of state for water, while the effects of salts are incorporated using Pitzer correlations for the activity of brines. The new model is able to predict ternary phase equilibria using interaction parameters fit to binary data. This allows predictive phase behavior calculations to be made for multiple components. The related system methanol + alkanes, where the alkane was a member of the homologous series propane to decane was modeled using the Statistical Associating Fluid Theory (SAFT) equation of state for both liquid-vapor (VLE) and liquid-liquid equilibria (LLE). It was shown that the PC and CK-SAFT equations of state were capable of representing the phase behavior to within a few percent (generally 1--4%) of the experimental data using binary interaction parameters that were weak linear functions of temperature and alkane molecular weight. The binary interaction parameters were fit to the VLE data and then applied to the LLE data with excellent results for the methanol + alkane systems from 1 to 150 MPa. For alkanes longer than octane, systematic deviation was observed.

Asphaltene precipitation and deposition can occur at different stages during petroleum production causing reservoir formation damage and plugging of pipeline and production equipment. Even though asphaltene deposition is a serious production hazard, deposition appears to occur only if precipitation is present. The main motivation of this work is to develop a general model for asphaltene precipitation and to understand the contribution of the surface material to asphaltene deposition. This dissertation presents a study of the effects of temperature, pressure, and composition on asphaltene phase separation prediction using the Statistical Associating Fluid Theory (SAFT) equation of state (EOS) and application of the theory to field cases. Furthermore, a molecular theory is used to predict the deposition tendency of asphaltene. Practical understanding of asphaltene precipitation applied to the oil field production is presented in this research project. A challenge overcame in this study was to translate this methodology to industrial application; initially, through the validation of the PC-SAFT EOS model as implemented in commercial computer software. Then, this work shows how SAFT qualitatively predicts different scenarios as actually occur in the field, i.e., the effect of gas injection, specifically, CO2, N2 and normal alkanes; oil based mud contamination and commingling of different live oil streams. These aspects were studied using crude oils from Deepwater Gulf of Mexico and Middle East. Finally, the impact of asphaltene precipitation considerations in a deepwater development project was studied based on experimental measurements of a hydrocarbon fluid when contacted with gas condensate from another zone. The evaluation was performed using multiphase thermal-hydraulic behavior coupled with the asphaltene PC-SAFT thermodynamic model. The PC-SAFT EOS adequately predicts the onset of asphaltene precipitation in all these cases. Simulation results agree with previous experimental reported work. On the depositional aspect a theoretical evaluation of the asphaltene adsorption behavior onto solid surfaces has been made to look for a relationship between the composition of the solution phase and the surface through the application of molecular theory. The asphaltene deposition tendency can be qualitatively described through the conventional Hamaker constant, which represents molecular van der Waals interactions between macroscopic bodies. Results show agreement with experimental observations.

The default assumptions used for interpreting Nuclear Magnetic Resonance (NMR) measurements with reservoir rocks fail for many sandstone and carbonate formations. This study provides quantitative understanding of the mechanisms governing NMR relaxation of formation fluids for two important cases in which default assumptions are not valid. The first is diffusional coupling between micro and macropore, the second is susceptibility-induced magnetic field inhomogeneities. Understanding of governing mechanisms can aid in better estimation of formation properties such as pore size distribution and irreducible water saturation. The assumption of direct correspondence between relaxation time and pore size distribution of a rock fails if fluid in different sized pores is coupled by diffusion. Pore scale simulations of relaxation in coupled micro and macropores are done to analyze the effect of governing parameters such as surface relaxivity, pore geometry and fluid diffusivity. A new coupling parameter (alpha) is introduced which quantifies the extent of coupling by comparing the rate of relaxation in a coupled pore to the rate of diffusional transport. Depending on alpha, the pores can communicate through total, intermediate or decoupled regimes of coupling. This work also develops a new technique for accurate estimation of irreducible saturation, an approach that is applicable in all coupling regimes. The theory is validated for representative cases of pore coupling in sandstone and carbonate formations. Another assumption used in NMR formation evaluation is that the magnetic field distribution in the pores corresponds to the externally applied field. However, strong field inhomogeneities can be induced in presence of paramagnetic minerals such as iron on pore surfaces of sedimentary rocks. A generalized relaxation theory is proposed which identifies three asymptotic relaxation regimes of motionally averaging, localization and free diffusion. The relaxation characteristics of the asymptotic regimes such as T 1/T2 ratio and echo spacing dependence are quantitatively illustrated by random walk simulations and experiments with paramagnetic particles of several sizes. The theory can aid in better interpretation of diffusion measurements in porous media as well as imaging experiments in Magnetic Resonance Imaging (MRI).

A high pressure heat flux calorimeter in isobaric, temperature-ramping mode has been used to measure the solubility of pure methane, pure carbon dioxide and methane-carbon dioxide mixtures. The solubility measurements emphasize a crystallization-like process taking place during hydrate formation and show a striking divergence from Henry's Law, the frequently used calculation procedure, prior to and during hydrate formation. These measurements were further used to determine the enthalpies of solution/dissociation, and entropies change. Moreover, the hydration numbers of these compounds provide some explanations and criteria of stability of the cages of gas hydrates in the host lattice. Finally, a kinetic study confirms the crystallization process of hydrate formation and exhibits a high level of supersaturation prior to hydrate formation and also a high consumption rate during hydrate formation.

This research explores a new method using foams for water production control in an oilfield. Reducing water production during oil production is an important objective impacting the profitability of a mature oilfield. Currently practiced methods using gel or polymer based systems either offer inadequate water flow reduction or suffer problems of proper placement in the field. Because of its properties, foam has the potential for use in water control. In this study, foams stable in presence of flowing water (washout stability) were developed using polymeric surfactants. A screening test was developed to measure the washout resistance of various conventional and polymeric surfactants. Foam from several polymeric surfactants such as triblock F108 and hydrophobically modified HMPA1 exhibited remarkable improvement in washout stability over conventional surfactants. Strong foam that offered a large resistance to flow of water was generated in a two-foot long sand pack with some of these polymeric surfactants. Again, the polymeric surfactants exhibited higher foam washout resistance than the conventional surfactants as predicted by the screening tests. Investigation of surfactant desorption from an air-water interface using bubble shape analysis showed that this improved foam washout resistance was due to almost irreversible adsorption of polymeric surfactants. Collapse of foam from polymeric surfactants at long times in the screening test was determined to be due to hydrodynamic effects and not desorption. Also, foam washout stability with polymeric surfactants in sand pack was found to be limited by air dissolution into flowing water. Scale-up calculations for oilfield geometries showed that foam from F108 can be stable for a long enough time, even with gas dissolution, for the process to be practicable. Foam stable to residual oil, expected in the water producing zones, was created by mixing an anionic surfactant CS-330 with nonionic F108. This is because ionic surfactants produce an electrostatic barrier that prevents entry of oil droplets into the air water interface. Flowing oil, however, produced a stable emulsion with this surfactant combination which offered a large resistance to flow. This was undesirable and was minimized by a brine flush to remove surfactant from the aqueous phase of the foam region before contact with flowing oil.

Oil recovery by water flooding is usually not effective because of capillary forces in fractured, oil-wet carbonate formations. Sodium carbonate/surfactant solution was used to enhance spontaneous imbibition between the fractures and the matrix by both wettability alteration and ultra-low interfacial tensions. Carbonate formations are usually oil-wet because the mineral-brine and oil-brine interfaces have zeta potentials of opposite sign. The resulting electrostatic attraction destabilizes the water film between the mineral and crude oil. The zeta potential of calcite can be reversed to be negative even at neutral pH, with dilute solutions of sodium carbonate and bicarbonate. Carbonate ion is a potential determining ion for carbonate formations. Thus sodium carbonate can promote water-wetness. Carbonate ion also sequesters calcium from the brine because of the small solubility product. The negative zeta potential and low calcium concentration greatly reduce the adsorption of anionic surfactants on the surface of carbonates. Another important effect of sodium carbonate is to generate natural soap in situ by saponifying organic acids in the crude oil. Optimal salinity was found to depend only on the soap-to-surfactant ratio. Below optimal salinity, sometimes a thin layer accumulated between the lower-phase microemulsion and excess oil. The IFT of excess oil with the equilibrated lower-phase microemulsion was high. However, ultra-low interfacial tension was observed when material from the thin layer was dispersed in the lower-phase or added to it. The existence of this thin layer made wide ultra-low interfacial tension possible. The alteration of wettability is graphically illustrated by observation with a polished marble plate. After aging in crude oil, the plate is strongly oil-wet in brine. When the brine is replaced with a sodium carbonate/surfactant solution, wettability can be altered to water-wetness to intermediate wetness. When sodium carbonate is the only salt, both drop size and contact angle are found to decrease with salinity to an equilibrium value. But when sodium carbonate concentration is fixed at one per cent, and sodium chloride is used to change ionic strength, contact angle is not found to change much with salinity, but drop size goes through a minimum at a salinity corresponding to the optimal salinity at the experimental condition. Oil in a narrow gap between two parallel plates remains in place when submerged in brine because of capillary forces. However, this oil is displaced by buoyancy when the brine is replaced with a sodium carbonate/surfactant solution. Displacement rate is found to be dependent on electrolyte concentration. No spontaneous imbibition occurred when a partially oil saturated reservoir core sample was placed in formation brine. Oil was spontaneously displaced when the brine was replaced with a sodium carbonate/surfactant solution. The recovery rate was found to scale with gravity drainage, not capillary imbibition.