Considerable effort worldwide has gone into monitoring heat and mass transfer at active volcanoes, as this information may provide clues about changes in volcanic activity and impending eruptions. One method used is the self-potential (SP) method, which has been employed on volcanoes to map hydrothermal systems and structural features and to monitor changes in the hydrothermal system due to volcanic activity. Continuous monitoring of SP has been employed on a few volcanoes and has produced encouraging results. This study presents new time series data collected from continuous monitoring stations at Masaya and Telica, and spatial series data from Masaya, Telica, and Cerro Negro, three active volcanoes in Nicaragua. The primary goals of this study were to determine whether correlations between SP anomalies and CO2 flux exist and to investigate temporal variations in temperature, SP, rainfall, and barometric pressure. To achieve these goals, SP and CO2 flux surveys were conducted on Masaya, Telica, and Cerro Negro, and continuous monitoring stations were installed on Masaya and Telica. The continuous monitoring station on Masaya recorded temperature, SP, rainfall, and barometric pressure. The station on Telica recorded temperature and SP. Profiles collected on Masaya and Cerro Negro show broad correlation between SP and CO2 flux. However, profiles on Telica revealed virtually no SP anomaly or CO2 flux for the majority of the profile, at the time of data collection. Data collected from the continuous monitoring station at Masaya showed a persistent positive SP anomaly that fluctuated between 60 and 240 mV. Rainfall was seen to supress the anomaly for time scales of several hours to several days. Correlations between temperature, SP, and barometric pressure were also seen at Masaya. Curiously, no increases in SP were seen during two temperature transients that occurred during volcanic activity in June and October. Continuous monitoring data from Telica showed only decreases in temperature and SP, which coincided with rainfall. The continuous monitoring data collected in this study and others have begun to provide a better understanding of the nature of SP anomalies, which may aid in the development of the SP method as a volcano monitoring tool.

A pore-scale understanding of fluid flow underpins the constitutive laws of continuum-scale porous media flow. Porous media flow laws are founded on simplified pore structure such as the classical capillary tube model or the pore-network model, both of which do not include diverging-converging pore geometry in the direction of flow. Therefore, modifications in the fluid flow field due to different pore geometries are not well understood. Thus this may translate to uncertainties on how flow in porous media is predicted in practical applications such as geological sequestration of carbon dioxide, petroleum recovery, and contaminant’s fate in aquifers. To fill this gap, we have investigated the role of a spectrum of diverging-converging pore geometries likely formed due to different grain shapes which may be due to a variety of processes such as weathering, sediment transport, and diagenesis. Our findings describe the physical mechanisms for the failure of Darcy’s Law and the characteristics of Forchheimer Law at increasing Reynolds Number flows. Through fundamental fluid physics, we determined the forces which are most responsible for the continuum-scale porous media hydraulic conductivity (K) or permeability. We show that the pore geometry and the eddies associated therein significantly modify the flow field and the boundary stresses. This has important implications on mineral precipitation-dissolution and microbial growth. We present a new non-dimensional geometric factor β, a metric for diverging-converging pore geometry, which can be used to predict K. This model for K based on β generalizes the original and now widely-used Kozeny (1927) model which was based on straight capillary tubes. Further, in order to better quantify the feasibility of geological CO2 sequestration, we have conducted laboratory fluid flow experiments at reservoir conditions to investigate the controls of media wettability and grain shapes on pore-scale capillary trapping. We present experimental evidence for the snap-off or formation of trapped CO2 ganglion. The total trapping potential is found to be 15% of porosity for a water-wet media. We show that at the pore-scale media wettability and viscous-fingering play a critical role in transport and trapping of CO2. Our investigations clearly show that that in single-phase flow pore geometry significantly modifies pore-scale stresses and impacts continuum-scale flow laws. In two-phase flows, while the media wettability plays a vital role, the mobility ratio of CO2 - brine system significantly controls the CO2 capillary trapping potential- a result which should be taken into consideration while managing CO2 sequestration projects. / text

With burgeoning world demand and a limited rate of discovery of new reserves, there is increasing impetus upon the industry to optimize recovery from already existing fields. 4D, or time-lapse, seismic imaging is an emerging technology that holds great promise to better monitor and optimise reservoir production. The basic idea behind 4D seismic is that when multiple 3D surveys are acquired at separate calendar times over a producing field, the reservoir geology will not change from survey to survey but the state of the reservoir fluids will change. Thus, taking the difference between two 3D surveys should remove the static geologic contribution to the data and isolate the timevarying fluid flow component. However, a major challenge in 4D seismic is that acquisition and processing differences between 3D surveys often overshadow the changes caused by fluid flow. This problem is compounded when 4D effects are sought to be derived from vintage 3D data sets that were not originally acquired with 4D in mind. The goal of this study is to remove the acquisition and imaging artefacts from a 4D seismic difference cube using Curvelet processing techniques.

Many places where natural gas hydrate occurs have a regionally extensive, bottom-simulating seismic reflector (BSR) at the base of the gas hydrate stability zone (GHSZ). This reflection marks the top of an underlying free-gas zone (FGZ). Usually, hydrate recycling (that produces gas as the stability field moves upward relative to sediments) is invoked to explain the presence and properties of the sub-BSR FGZ. However, this explanation is not always adequate: FGZs are often thicker in passive-margin environments where hydrate recycling is relatively slow, than in convergent-margin environments where hydrate recycling is relatively fast (e.g. Blake Ridge compared with Cascadia). Furthermore, some areas with thick FGZs and extensive BSRs (e.g. west Svalbard) have similar rates of hydrate recycling to northern Gulf or Mexico, yet the latter has no regional BSR. Here we discuss a gas-forming mechanism that operates in addition to hydrate recycling, and which produces a widespread, regional, BSR when gas is transported upward through the liquid phase; this mechanism is dominant in tectonically passive margins. If the gas-water solubility decreases downward beneath the GHSZ (this occurs where the geothermal gradient and the pressure are relatively high), low rates of upward fluid flow enable pore water to become saturated in a thick layer beneath the GHSZ. The FGZ that this produces achieves a steady-state thickness that is primarily sensitive to the rate of upward fluid flow. Consequently, geophysical observations that constrain the thickness of sub-BSR FGZs can be used to estimate the regional, diffuse, upward fluid flux through natural gas-hydrate systems.

Occurrences of carbonate-cemented nodules and concretions exposed on the seafloor that contain cements with light carbon isotopes, indicating a contribution of methane-derived carbon, are commonly interpreted to be indicators of seafloor fluid venting. Thus, their presence is commonly used as an indicator of the possible occurrence of methane gas hydrate within the near subsurface. While some of these carbonates exhibit facies that require formation on the seafloor, the dominant fine-grained lithology associated with these carbonates indicates they were formed as sedimenthosted nodules within the subsurface and are similar to nodules that are obtained from the subsurface in Deep Sea Drilling Project, Ocean Drilling Project, and Integrated Ocean Drilling Project boreholes. Here we present the hypothesis that the occurrence of these carbonates on the seafloor may instead indicate areas of persistent seafloor erosion.

Natural gas hydrates occur on most continental margins in organic-rich sediments at water depths >450 m (in polar regions >150 m). Gas hydrate distribution and abundance, however, varies significantly from margin to margin and with tectonic environment. The National Gas Hydrate Program (NGHP) Expedition 01 cored 10 sites in the Krishna-Godawari (K-G) basin, located on the southeastern passive margin of India. The drilling at the K-G basin was comprehensive, providing an ideal location to address questions regarding processes that lead to variations in gas hydrate concentration and distribution in marine sediments. Pore fluids recovered from both pressurized and non-pressurized cores were analyzed for salinity, Cl-, SO4 2-, alkalinity, Ca2+, Mg2+, Sr2+, Ba2+, Na+, and Li+ concentrations, as well as 􀀂13C-DIC, 􀀂18O, and 87/86Sr isotope ratios. This comprehensive suite of pore fluid concentration and isotopic profiles places important constraints on the fluid/gas sources, transport pathways, and CH4 fluxes, and their impact on gas hydrate concentration and distribution. Based on the Cl- and 􀀂18􀀁 depth profiles, catwalk infrared images, pressure core CH4 concentrations, and direct gas hydrate sampling, we show that the occurrence and concentration of gas hydrate varies considerably between sites. Gas hydrate was detected at all 10 sites, and occurs between 50 mbsf and the base of the gas hydrate stability zone (BGHSZ). In all but three sites cored, gas hydrate is mainly disseminated within the pore space with typical pore space occupancies being 􀀁2%. Massive occurrences of gas hydrate are controlled by high-angle fractures in clay/silt sediments at three sites, and locally by lithology (sand/silt) at the more “diffuse” sites with a maximum pore space occupancy of ~67%. Though a majority of the sites cored contained sand/silt horizons, little gas hydrate was observed in most of these intervals. At two sites in the K-G basin, we observe higher than seawater Cl- concentrations between the sulfate-methane transition (SMT) and ~80 mbsf, suggesting active gas hydrate formation at rates faster than Cl- diffusion and pore fluid advection. The fluids sampled within this depth range are chemically distinct from the fluids sampled below, and likely have been advected from a different source depth. These geochemical results provide the framework for a regional gas hydrate reservoir model that links the geology, geochemistry, and subsurface hydrology of the basin, with implications for the lateral heterogeneity of gas hydrate occurrence in continental margins.

The increasing concentration of CO_(2) has been linked to global warming and changes in climate. Geologic sequestration of CO_(2) in deep saline aquifers is a proposed greenhouse gas mitigation technology with potential to significantly reduce atmospheric emissions of CO_(2). Feasibility assessments of proposed sequestration sites require realistic and computationally efficient models to simulate the subsurface pressure response and monitor the injection process, and quantify the risks of leakage if there is any. This study investigates the possibility of obtaining closed form expressions for spatial distribution of CO_(2) injected in brine aquifers and gas reservoirs. Four new semi-analytical solutions for CO_(2) injection in brine aquifers and gas reservoirs are derived in this dissertation. Both infinite and closed domains are considered in the study. The first solution is an analysis of CO_(2) injection into an initially brine-filled infinite aquifer, exploiting self–similarity and matched asymptotic expansion. The second is an expanding to the first solution to account for CO_(2) injection into closed domains. The third and fourth solutions are analyzing the CO_(2) injection in infinite and closed gas reservoirs. The third and fourth solutions are derived using Laplace transform. The brine aquifer solutions accounted for both Darcyian and non-Darcyian flow, while, the gas reservoir solutions considered the gas compressibility variations with pressure changes. Existing analytical solutions assume injection under constant rate at the wellbore. This assumption is problematic because injection under constant rate is hard to maintain, especially for gases. The modeled injection processes in all aforementioned solutions are carried out under constant pressure injection at the wellbore (i.e. Dirichlet boundary condition). One major difficulty in developing an analytical or semi-analytical solution involving injection of CO_(2) under constant pressure is that the flux of CO_(2) at the wellbore is not known. The way to get around this obstacle is to solve for the pressure wave first as a function of flux, and then solve for the flux numerically, which is subsequently plugged back into the pressure formula to get a closed form solution of the pressure. While there is no simple equation for wellbore flux, our numerical solutions show that the evolution of flux is very close to a logarithmic decay with time. This is true for a large range of the reservoir and CO_(2) properties. The solution is not a formation specific, and thus is more general in nature than formation-specific empirical relationships. Additionally, the solution then can be used as the basis for designing and interpreting pressure tests to monitor the progress of CO_(2) injection process. Finally, the infinite domain solution is suitable to aquifers/reservoirs with large spatial extent and low permeability, while the closed domain solution is applicable to small aquifers/reservoirs with high permeability.

I present in this thesis a fluid flow and heat transfer model for porous media using the lattice Boltzmann method (LBM). A computer simulation of this process has been developed and it is written using MATLAB software. The simulation code is based on a two dimensional model, D2Q9. Three physical experiments were designed to prove the simulation model through comparision with numerical results. In the experiments, physical properties of the air flow and the porous media were used as input for the computer model. The study results are not conclusive but show that the LBM model may become a reliable tool for the simulation of natural convection heat transfer in porous media. Simulations leading to improved understanding of the processes of air flow and heat transfer in porous media may be important into improving the efficiency of methods of air heating or cooling by passing air through fragmented rock.

This thesis is aimed to calculate the effective permeability tensor and to simulate the fluid flow in naturally fractured reservoirs. This requires an understanding of the mechanisms of fluid flow in naturally fractured reservoirs and the detailed properties of individual fractures and matrix porous media. This study has been carried out to address the issues and difficulties faced by previous methods; to establish possible answers to minimise the difficulties; and hence, to improve the efficiency of reservoir simulation through the use of properties of individual fractures. The methodology used in this study combines several mathematical and numerical techniques like the boundary element method, periodic boundary conditions, and the control volume mixed finite element method. This study has contributed to knowledge in the calculation of the effective permeability and simulation of fluid flow in naturally fractured reservoirs through the development of two algorithms. The first algorithm calculates the effective permeability tensor by use of properties of arbitrary oriented fractures (location, size and orientation). It includes all multi-scaled fractures and considers the appropriate method of analysis for each type of fracture (short, medium and long). In this study a characterisation module which provides the detail information for individual fractures is incorporated. The effective permeability algorithm accounts for fluid flows in the matrix, between the matrix and the fracture and disconnected fractures on effective permeability. It also accounts for the properties of individual fractures in calculation of the effective permeability tensor. The second algorithm simulates flow of single-phase fluid in naturally fractured reservoirs by use of the effective permeability tensor. This algorithm takes full advantage of the control volume discretisation technique and the mixed finite element method in calculation of pressure and fluid flow velocity in each grid block. It accounts for the continuity of flux between the neighbouring blocks and has the advantage of calculation of fluid velocity and pressure, directly from a system of first order equations (Darcy???s law and conservation of mass???s law). The application of the effective permeability tensor in the second algorithm allows us the simulation of fluid flow in naturally fractured reservoirs with large number of multi-scale fractures. The fluid pressure and velocity distributions obtained from this study are important and can considered for further studies in hydraulic fracturing and production optimization of NFRs.

Akademisk avhandling--Karolinska institutet, Stockholm. / Added t.p. with thesis statement inserted. Includes bibliographical references.