A novel permeability reduction process has been developed to control fluid flow in porous media. The procedure generally involves use of bacteria to actively precipitate calcium carbonate as a mineral plugging and cementing agent. This process may be suitably employed to enhance the recovery of oil from oil reservoirs, cement unconsolidated sand underground, or to control the flow of contaminants in an aquifer.

SPE Members Abstract Downward displacement of oil by inert gas injected in a reservoir either at initial oil and connate water conditions or, in a reservoir depleted by waterflooding, results in very high oil recovery efficiencies under strongly water-wet conditions in both unconsolidated and consolidated porous media respectively. Advances made in porous media respectively. Advances made in directional drilling technology and increased understanding of the mechanisms and conditions that maximize recovery efficiencies can make the inert gas injection process of oil recovery feasible for a wide variety of oil reservoirs. This paper presents experimental results and discussion of a presents experimental results and discussion of a series of experiments designed for the study of:production characteristics under immiscible inert gas driven gravity drainage conditions;microscopic mechanisms of displacements and the determination of the rate of production by gravity drainage in capillary tubes having square cross-section; andfluid distributions and oil bank formation using the x-ray computer tomography (CT) scanning facilities we recently established in our laboratory. Introduction Gas injection is being increasingly applied as a secondary or tertiary recovery process, particularly in reservoirs with a reasonable dip particularly in reservoirs with a reasonable dip angle, preferably of high permeability and containin light oil. In such reservoirs a gravity-stable injection scheme is often possible, leading to high sweep efficiencies. There are numerous projects for immiscible gas injection schemes reported in literature which have demonstrated in laboratory experiments and in field performance analysis that very high oil recoveries of residual oil are achieved if gravity drainage (the self propulsion of oil downward in a reservoir) is the dominant production mechanism. An extensive review of the literature is beyond the scope of this paper and can be found elsewhere. Pioneering studies involving the drainage of liquids from unconsolidated sands were done by Stahl et al., and Terwilliger et al. Imagine a vertical column of water-wet glass beads saturated first with brine and subsequently oil flooded to establish initial oil and connate water conditions. Next, consider the injection of air or nitrogen at the top of the column at constant pressure and the production kept at controlled flow rate such that the pore velocity of the gas-oil contact (GOC) is relatively small (e.g. 10(-2) to 10(-1) m/d). Also consider that at the production end at the bottom of the column there is production end at the bottom of the column there is a semipermeable membrane that permits the oil and the water to go through but not the gas when it eventually arrives at the producing end of the column. This experiment has been referred to as "controlled drainage of continuous oil" and has been routinely performed in our laboratory. Overall recovery efficiences were very high (90% to 99% of the oil in place, in glass bead columns of different dimensions). In earlier studies of gravity drainage very low residual oil saturations have also been reported in water-wet media. Dumore and Schols concluded that after the relatively short period in which the main oil production takes place (i.e. in the free fall production takes place (i.e. in the free fall drainage) the drainage of oil in the presence of connate water and injected gas is possibly governed by film flow of bypassed oil. Hagoort stated that gravity drainage can be an effective way of oil production. In his theoretical discussion, the production. In his theoretical discussion, the importance of relative permeabilities to oil was addressed and used th centrifuge technique in order to get the exact representation of field conditions. P. 223

Petroleum-induced water repellency in soils is a problem that has been thought to develop randomly following contamination and then remediation of a site with petroleum. The emergence of the phenomenon can occur within months or years of original contamination and with seemingly no warning. Low-field NMR has been used to study these soils and, specifically, the processes of water uptake that occur in them. Critical aspects in the development of this phenomenon have been identified as well--specifically, a dependence on climatic events in the area and contamination levels that contribute are suggested.

Coalbed Methane (CBM) shows great potential to be an important energy source. One key factor for the successful development of CBM processes is to characterize coal on its moisture and gas content. Usually, the moisture and gas content of coal are determined from laboratory analysis. Low-field nuclear magnetic resonance (NMR) is a relatively new technique used in logging and in the analysis of fluids contained in reservoir rocks. This paper investigates the potential for coal characterization by low-field NMR. Low-field NMR detects hydrogen-bearing molecules and, in reservoir rock samples, distinguishes between ‘free’ bulk fluid and ‘bound’ surface fluid. Coal contains free water in the cleats as well as moisture that forms an integral part of the coal structure. Methane gas is a light hydrocarbon gas and coal contains free methane gas in fractures and adsorbed methane in internal surfaces. NMR characterization of moisture and adsorbed gas in coal and implications for moisture, adsorption isotherm and gas content measurements are explored. Experiments of moisture-free coal, moist coal and coal/water mixtures indicated drastically different spectra. From these spectra, free and bound water could be estimated using a methodology that is currently applied in clay-rich formations. In this paper, two sets of data are presented. First, measurements at ambient conditions provided a reference to other conventional moisture and cutoff data. Second, a high-pressure cell for the measurement of adsorbed coal was used and comparisons were made. Coal samples in the form of powder and chunk were used. The paper focuses on the methods and results to date. Introduction Coalbed methane (CBM) has evolved into a commercially profitable source of natural gas. Canada has vast resources of coal and it has been estimated that the total in-place reserves are 36 ? 1012 m3. Over 60% of Canada's CBM assets are in Alberta(1). Coalbed methane has the potential of contributing a significant portion of Canadian natural gas production in the near future. One key factor for the successful development of CBM processes is to characterize coal on its moisture and gas content. Usually, the moisture of coal is determined from coal proximate analysis and the gas content of coal is determined by the desorption measurement in the laboratory. Low-field NMR is a relatively new technique used in logging and in the analysis of fluids contained in reservoir rocks. Nuclear magnetic resonance occurs when the nuclei of certain atoms (i.e. hydrogen proton) are immersed in a static magnetic field and exposed to a second oscillating magnetic field(2). NMR provides a non-destructive analytical method of detecting hydrocarbons in reservoirs(3) and characterizing the hydrocarbon gas(4). Generally, the NMR spectrum can provide three types of information: the quantities of the fluids in the rock, the mobility (viscosity) of these fluids and information about the pores that contain these fluids. As a source rock and at the same time a reservoir rock, coal contains large amounts of water and methane. Water exists as free water in the cleats as well as the moisture that forms an integral part of the coal structure.

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Very high oil recoveries are achieved when an inert gas displaces continuous oil or residual oil downwards in water wet columns of glass beads and in sandstone cores, provided that a semi permeable membrane is used at the production end to prevent gas breakthrough. In this paper, pore level mechanisms that control this displacement process are elucidated, as revealed by experiments in 2-dimensional pore network micromodels and unconsolidated columns of glass beads. Visualizations of the displacement mechanisms are presented and their effect on oil production is discussed. By applying principles of capillarity and by using well defined pore geometries, equations have been developed for predicting both water and oil distributions at the pore level. Introduction Recent laboratory studies have shown that gravity assisted inert gas injection has the potential to become an efficient method of oil recovery. Kantzas et. al demonstrated the potential capabilities of such a method by conducting experiments in unconsolidated cores of various sizes. In their experiments, all core samples were saturated first with brine which was in turn displaced by oil to the residual wetting phase saturation condition. The cores were positioned vertically and air or nitrogen was injected at the top of the column to displace the oil downwards. At the end of the displacement process, 99% of the oil was recovered in all unconsolidated columns while the recovery in consolidated columns was 80% or better. Other experiments were conducted beginning with h cores at waterflood residual oil conditions. At nitrogen were injected at the top and displaced vertically downwards both water and oil. The efficiency of oil recovery was 70% to 94% for the unconsolidated media and 55% to 85% for the consolidated media. The experiments in unconsolidated media provided some initial visualizations of the mechanisms of displacement. A fairly uniform displacement front was developed for the case of displacing continuous oil. In the case of displacing discontinuous oil, two different regimes were identified. One regime was that of controlled drainage conditions where air advanced at very slow flow rates and an oil bank was formed between the water bank and the gas bank zones. Another regime was that of free drainage conditions where gas advanced at high flow rates towards the production end and bypassed the residual oil blobs. Under these conditions lower recovery efficiency was observed. The aforementioned experiments have shown that the isolated blobs can be reconnected and form a continuum which can be efficiently displaced. Leakage mechanisms have been shown to control the displacement of the wetting phase and very low residual wetting phase saturation can be achieved at high capillary pressures. Similar mechanisms can affect the displacement of residual oil in waterwet media when inert gas is the displacing phase. In order to investigate the different types of displacement mechanisms at the pore level, a series of micromodel experiments were conducted. In this paper visualizations of three phase immiscible displacements and theoretical considerations of fluid distributions at the pore level are presented. EXPERIMENTAL a. Experiments in 2-D Micromodels Transparent to flow 2-dimensional micromodels of various pore structure geometries have been fabricated and used by a number of investigators using photofabrication and etching techniques (for details the reader is referred to McKellar and Wardlaw and Chatzis et. al). Using this technique, pore network models were designed on glass plates which were then fused in a muffle furnace. P. 297^

Cover: The cover image shows a 3D structure of a porous polyethylene particle reconstructed from X‐ray computed tomography images (left). Dynamic simulations of monomer degassing from reconstructed particles were carried out (upper right). Artificial particles with bidisperse granular morphology were alternatively employed in reaction and transport modeling (lower right). Further details can be found in the article by L. Seda, A. Zubov, M. Bobak, J. Kosek,* A. Kantzas on page 495.

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