The kinetics of low-temperature oxidation (LTO) of crude oils in porous media was studied. Isothermal integral reactor data were analyzed to obtain rate equations for the over-all rate of the partial oxidation reactions at temperatures below partial oxidation reactions at temperatures below 500 deg. F. The reaction order with respect to oxygen was found to be between 0.5 and 1.0. The order of the reaction was dependent upon the crude but independent of the properties of the porous medium. The activation energy of the reaction was insensitive to the type of crude or porous medium and is in the neighborhood of 31,000 Btu/lb mol. LTO reactions were found to be in the kinitics-influenced region. The measured reaction rates for a 19.9 deg. API and a 27.1 deg. API crude indicated higher oxidation rates under similar reaction conditions for the higher API gravity crude. Light crudes appear to be m ore susceptible to partial oxidation at low temperatures because of the react ed oxidation reactions rather than by carbon oxidation. Other information includes the fraction of reacted oxygen utilized in carbon atom oxidation by the LTO reaction and the molar ratio of CO2 and CO produced in the low-temperature region. Effect of partial oxidation of the crude on the in-situ combustion process was studied by experimentally simulating the zones preceding the combustion front where temperatures and injection rates of linear reservoir model were programmed with time according to a predesigned schedule. Oxidation of the crude at temperatures below 400 deg.F had significant effects on the behavior of the crude-oil/water system in the porous medium at elevated temperatures and on the fuel available for combustion. A substantial decline in the recoverable oil from the evaporation and cracking zones, an increase in fuel deposition, and drastic changes in fuel characteristics and coked sand properties were obtained when the crude was subjected to LTO during the simulation process. Introduction The application of thermal energy to petroleum reservoirs as a means of increasing crude oil recovery has been given a great deal of attention. In underground combustion, thermal energy is induced by the partial burning of the crude oil in situ. The production of heat by the exothermic oxidation reactions of the hydrocarbons constitutes a unique feature of the in-situ combustion process. The chemical reactions and the accompanying heat released create a new temperature profile and cause drastic redistribution in the reservoir fluid saturations. With oxygen available in the transient zones of variable temperature and hydrocarbon saturations, several oxidation reactions of differing nature can take place during an underground combustion process. Because of the complex composition of process. Because of the complex composition of crudes and the great number of reaction products that can be produced, it is convenient to classify the hydrocarbon oxidation reactions ascombustion reactions that take place in the high-temperature combustion zone (above 600 deg. F) with CO2, CO, and H2O as the principal reaction products andpartial oxidation or low-temperature products andpartial oxidation or low-temperature (LTO) reactions that occur in zones where the temperature is lower than 600 deg. F. Several partial oxidation reactions are known to take place, producing primarily water and oxygenated producing primarily water and oxygenated hydrocarbons such as carboxylic acid aldehydes, ketones, alcohols, and hydroperoxides. High-temperature combustion reactions are desirable because they generate most of the heat required for the in-situ combustion process. Partial oxidation reactions, on the other hand, are in most cases undesirable because of their adverse effect on the viscosity and distillation characteristics of the crude. SPEJ P. 253
Introduction Relative permeabilities are factual data necessary to any prediction of reservoir production behavior. One important problem in determining relative permeabilities of porous media to gas is the effect of gas slippage on these determinations. Since certain aspects of the slippage phenomenon still remain unknown, this study is particularly concerned with that problem. The validity of the theory of gas slippage as it is applied to the flow of gas through porous media has been well established. Therefore, in determining the permeabilities of porous media to gas by ordinary laboratory procedure, i.e., at atmospheric pressure, the slippage correction should be considered. Rose performed experiments on gas relative permeabilities which indicated that the effect of gas slippage on the measured effective gas permeabilities at various liquid saturations decreased with an increase in liquid saturation. Following Rose, it was substantiated experimentally that the effective gas permeabilities at the various liquid saturations extrapolated to infinite mean pressure were the same as the non-wetting liquid permeabilities at the same saturations. This same paper also presented data which showed that the magnitude of the slippage between those values of gas effective permeability determined at atmospheric pressure and those found by extrapolation to infinite mean pressure decreased with an increase in liquid saturation. However, these experiments were not performed at liquid saturations above 30 per cent. Therefore, the purpose of this experimental work was to determine the effect of gas slippage on permeability measurements at liquid saturations in excess of 30 per cent. Apparatus Five core samples were used in this work: two synthetic Alundum samples (A-1, and A-2), a Nichols Buff sandstone sample (NB-13), and two samples from producing formations, a Soso sandstone (S-1), and a vugular dolomitic limestone (R-7). The core samples ranged in permeability from 32 to 663 md. These cores were chosen because they represented a fairly wide range of permeabilities and probably a considerable difference in pore size and pore size distribution.
Air and water permeabilities of a large number of samples from the Pittsburghand Pocahontas coals were measured at various overburden and mean flowpressures. A wide variation (< 0.0 1 to > 100 md) in the air and waterpermeabilities was obtained for each type of coal, and flow was primarilythrough microfractures. Overburden pressure has the most significant effect onthe single-phase permeability. Considerable hysteresis was observed for bothair and water permeabilities. Gas permeabilities are affected to a lesserdegree by mean flow pressure above atmospheric. However, at subatmospheric meanpressures, appreciable increase in permeability occurs for low-permeabilitysamples. This was attributed to gaseous molecules desorbed at pore necks. At highoverburden pressure (~> 400 psig) water permeabilities are smaller than orequal to air permeabilities measured at the same pressures. Introduction The permeability of coal to gas and water is of interest to engineers in boththe mining and the petroleum industries. Much of the interest of the miningengineer stems from concern for the health and safety of the coal miner becausethe flow of methane into coal mines is one of the major causes of mine disasters in thiscountry. Some deep mines produce 10 to 15 MMscf/D of methane and require thecirculation of as much as 10 to 15 tons of air per ton of coal mined in orderto clear the gas from the mine. If this little-known source of natural gascould be produced from the coal before the coal is mined, it would help relievethe gas shortage as we11 as protect the safety of the coal miner. In recent years a number of petroleum companies have shown an interest in coalas a primary energy material that can be converted into electrical energy orinto gaseous and liquid products. Both above- and below-ground processes arebeing studied intensively. Knowledge of the basic permeability and relativepermeability of coal to gas and water should be very useful to petroleumengineers contemplating these new processes for the conversion of coal intoenergy forms suitable for the consumer. Although some studies of the permeability of coal to gas and to water have beenconducted, no gas/water relative permeability studies have been reported eventhough the presence of significant quantities of water is known to have amarked effect on the flow of methane from the coal seam. In this and a relatedpaper, we present the results of gas/water relative permeability studies onPittsburgh and Pocahontas coal samples.
An experimental procedure for determining the effectiveness of CO2 injection into methane-containing coal samples for the purpose of enhancing methane production is described. Experimental results on production is described. Experimental results on both dry and water saturated samples reveal that CO2 injection greatly enhances both production rate and recover efficiency. Most effective is a cyclic CO2 injection-gas production technique which recovered essentially all of the adsorbed methane in the 3 1/2" core samples used in the experiments. Introduction The coal which lies buried beneath the United States at depths of less than 3000 feet is thought to contain nearly 300 trillion standard cubic feet of pipeline quality gas. This exceeds the current pipeline quality gas. This exceeds the current proved gas reserves in the U.S. and represents a proved gas reserves in the U.S. and represents a significant possible supplement to dwindling supplies. The natural gas found in virgin coal beds is predominantly methane, usually exceeding 80%. Very predominantly methane, usually exceeding 80%. Very small percentages of ethane, propane, butane and pentane have been detected. Carbon dioxide and pentane have been detected. Carbon dioxide and nitrogen may be as high as 15% in gas from virgin coal. Most of the gas present in coal beds is adsorbed on the coal surfaces and desorption is normally a very slow process. In addition to the desirability of producing this gas as an energy source there is the added important advantage from a safety standpoint of demethanating a coal bed prior to mining. Attempts to produce the gas in coal through vertical well bores by pressure drawdown have generally not been commercially successful because of low production rates. Differing theories on the transport of gases through coal have been proposed by Cervik, Kissell, Skidmore and Chase and Kuuskraa, et. al to explain these low production rates. None of these has concluded that desorption rate is the mechanism which controls production rates from wells drilled into coal beds. production rates from wells drilled into coal beds. A key publication by Every and Delosso in 1972 showed that carbon dioxide proved to be very effective in displacing methane from crushed coal under laboratory imposed flow conditions at ambient temperature. This led to the proposal that competitive adsorption-desorption of methane by carbon dioxide might provide an efficient means for rapid degassification of coal y beds and thereby increased recovery rates of methane from vertical well bores. This paper describes a laboratory procedure for measuring the effectiveness of carbon dioxide in replacing methane from 3 1/2" diameter samples of Pittsburgh coal and also presents the experimental results. EXPERIMENTAL PROCEDURE The coal from the Pricetown mine in West Virginia was delivered in large lumps which were then stored under water until cored for use in the experiments. The experimental apparatus is represented schematically in Figure 1 and pictorially in Figure 2. The pressure vessels used were 4 inch (10.16 cm) I.D. ant pressure vessels used were 4 inch (10.16 cm) I.D. ant 12 inches (30.48 cm) long. The vessels were designed for operating pressures of 100 psi (4.78 Pa) and 200 psi (9.56 Pa). The coal samples were cut to diameters of 3 1/2 or 3 3/4 inches (8.89 or 9.555 cm) and varying lengths between 2 to 4 inches (5.08 to 10.16 cm) and stacked in the vessels to a total height of approximately 11 1/2 inches (29.21 cm). The system was evacuated for several hours. Methane was expanded from a constant volume pressure cylinder into the vessel containing the coal resulting in methane adsorption on the coal surfaces. As methane was being adsorbed, the pressure in the system declined and the amount of pressure in the system declined and the amount of methane adsorbed was determined by material balance. At some arbitrarily selected time, usually six to eight days, the pressure in the system was noted, and the amount of adsorbed methane calculated. In some cases, in order to get a greater quantity of methane adsorbed, the pressure was increased and the process repeated several times. When the desired amount of methane had been adsorbed the excess gas in the vessel was vented to atmospheric pressure. At this point the natural desorption production cycle was begun and continued until no more gas was being produced, or was stopped after some arbitrarily chosen time interval. P. 65
A linear Berea sand pack, initially containing three phases -- oil, water and air - was used to simulate experimentally the processes in the zones from the water bank through the evaporation and visbreaking region. Simulations using such process parameters as oil composition, system pressure, parameters as oil composition, system pressure, and gas injection rate were conducted. Every simulation followed programmed ascending-temperature steps with each step being approximately isothermal. The relative importance of each mechanism causing nonisothermal liquid movement was quantitatively determined and liquid saturation distributions were obtained. Results of the experiments showed that gas stripping was one of the main mechanisms responsible for oil flow in the hot water bank and that steam distillation was the chief mechanism for the oil movement in the steam plateau. Both mechanisms were primarily controlled by oil composition, system pressure and gas injection rate. The oil- and water-saturation distributions were reconstructed from the experimental results. A first-order equation approximated the oil saturation in the regions simulated and a second-order equation approximated the water-saturation distribution. Introduction Laboratory experiments, mathematical models, and field tests have been widely used to investigate the in-situ combustion process. Invariably, the results of these investigations have confirmed that the complex in-situ process possesses a number of distinct transient regions of varying physical and chemical importance. physical and chemical importance. Mechanisms associated with each of these regions have been qualitatively described. In general, these descriptions are based on gross experimental observations such as production history, temperature profile, produced fluid properties, etc. These qualitative descriptions of properties, etc. These qualitative descriptions of in-situ mechanisms are principally sound, but the scarcity of quantitative demonstration of nonisothermal liquid behavior, liquid-saturation distribution and process parameter effects on the mechanisms demands further investigation. This paper attempts to provide some quantitative information on several important mechanisms associated with in-situ combustion. A simple linear laboratory model is used to simulate the processes in the regions, starting from the water bank and ending at the evaporation and visbreaking region, which immediately precede the cracking region and combustion front. The experimental results give oil- and water-saturation distributions which should be useful in mathematical simulation and oil recovery estimation. REGIONS OF IN-SITU COMBUSTION Kuhn and Koch observed at least four coexistent transient regions in their experimental work using linear combustion tubes. Tadema performed in-situ combustion in a glass tube and described the mechanisms that would take place in each of these transient regions. Wu estimated the relative length of these regions in a combustion tube process under various experimental conditions. process under various experimental conditions. A schematic diagram of these regions is shown in Fig. 1. These regions were discretely reconstructed based on the description of Tadema and liquid production and temperature histories at the outlet end of a typical combustion tube experiment (performed by the Gulf Research and Development Co.). Starting from the injection end, these regions may be designated as the burned zone, combustion zone, cracking region, evaporation and visbreaking region, steam plateau, water bank, oil bank and initial zone. Each region has definite temperature and fluid-saturation characteristics. SPEJ P. 38
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