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.

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This study utilises seismic data to improve understanding of the subsurface fluid flow behaviour in the Taranaki and Great South Basins offshore New Zealand. The aim of this study is to characterise fluid flow features and to investigate their genesis, fluid origins and implications for subsurface fluid plumbing system by integrating seismic interpretation and 3D petroleum systems modelling techniques. After an early phase studying Pliocene pockmarks in the Taranaki Basin, this study has been focused on the subsurface fluid plumbing system and on the fluid expulsion history in the Great South Basin. The Taranaki Basin lies on the west coast and offshore of the North Island, New Zealand. The seismic interpretation revealed that paleo-pockmark formation in the study area relates to fluid escape due to a rapid sediment loading environment in a distal fan setting. Seismic analysis rules out any links between the paleo-pockmarks and faulting. The relationship between paleo-pockmark occurrence and fan depositional thickness variations suggests that pore-water expulsion during overburden progradation is the most likely cause of the paleo-pockmarks. The rapid sediment loading generated overpressure which was greatest on the proximal fan due to a lateral gradient in overburden pressure. Fluids were consequently forced towards the fan distal parts where, eventually, the pore pressure exceeded the fracture gradient of the seal. The Great South Basin lies off the southern coast of the South Island of New Zealand and is located beneath the modern shelf area. Evidence for past and present subsurface fluid flow in this basin is manifested by the presence of numerous paleo-pockmarks, seabed pockmarks, polygonal fault systems, bright spots and bottom simulating reflections (BSR), all of which help constrain aspects of the overburden plumbing system and may provide clues to deeper hydrocarbon prospectivity in this frontier region. The various types of fluid flow features observed in this study are interpreted to be caused by different fluid origins and mechanisms based on evidences from seismic interpretation in the study area. The possible fluid origins which contribute to fluid flow features in the Great South Basin are compactional pore water as well as biogenic and thermogenic hydrocarbons. Using 3D seismic attribute analysis it was possible to highlight the occurrence of these features, particularly polygonal faults and pockmarks, which tend to be hosted within fine-grained sequences. Paleo- and present-day fluid flow features were investigated using 3D basin and petroleum systems modelling with varying heat flow scenarios. The models predict that thermogenic gas is currently being generated in mid-Cretaceous sedimentary sequences and possibly migrates along tectonic faults and polygonal faults feeding present-day pockmarks at the seabed. The models suggest that biogenic gas was the main fluid source for the Middle Eocene paleo-pockmarks and compactional pore fluid may be the main fluid contributor to the Late Eocene paleo-pockmarks. Different heat flow scenarios show that only mid-Cretaceous source rocks have reached thermal maturity in the basin, whilst Late Cretaceous and Paleocene source rocks would be largely immature. The observations and interpretations provided here contribute to the ongoing discussion on basin de-watering and de-gassing and the fluid contributors involved in pockmark formation and the use of pockmarks as a potential indicator of hydrocarbon expulsion. It is clear from this study that seismically-defined fluid flow features should be integrated into petroleum systems modelling of frontier and mature exploration areas in order to improve our understanding on fluid phases, their migration routes, timings and eventual expulsion history.

Viscoelastic fluid flow with immersed boundaries of complex geometry is widely found both in nature and engineering processes. Examples include haemocytes moving in human blood flow, self-propulsion of microscopic organisms in complex liquids, hydraulic fracturing with sand in oil flow, and suspension flow with viscoelastic medium. Computational modelling of such systems is important for understanding complex biological processes and assisting engineering designs. Conventional simulation methods use conformed meshes to resolve the boundaries of complex geometry. Dynamically updating the conformed mesh is computationally expensive and makes parallelization difficult. In comparison, Cartesian grid methods are more promising for large scale parallel simulation. Using Cartesian grid methods to simulate viscoelastic fluid flow with complex boundaries is a relatively unexplored area. In this thesis, a sharp interface Cartesian grid method (SICG) and a smoothed interface immersed boundary method (SIIB) are developed in order to simulate viscoelastic fluids in complex geometries. The SICG method shows a better prediction of the stress on stationary boundaries while the SIIB method shows reduced non-physical oscillations in the computation of drag and lift forces on moving boundaries. Parallel implementations of both solvers are developed. Convergence of the numerical schemes is shown and the implementations are validated with a few benchmark problems with both stationary and moving boundaries. This study also focuses on the simulation of flows past 2D cylindrical or 3D spherical particles. Lateral migration of particles induced by inertial and viscoelastic effects are investigated with different flow types. Equilibrium positions of inertia-induced migration are reported as a function of the particle Reynolds number and the blockage ratio. The migration in the viscoelastic fluid is simulated from zero elastic number to a finite elastic number. The inclusion of both inertial and viscoelastic effects on the lateral migration of a particle is the first of its kind. New findings are reported for the equilibrium positions of a spherical particle in square duct flow, which suggest the need for future experimental and computational work.