A set of experiments is described in which CO2 is injected into large cores of CH4- and water-saturated bituminous coal at elevated pressures. CO2 at Pressures up to 800 psig [5516 KPa] is used to simulate the enhanced recovery of in-situ CH4 from coal beds. CO2 injection increases the recovery of CH4 by a factor of two to three times that achieved in simple desorption by pressure drawdown and atmospheric diffusion. In pressure drawdown and atmospheric diffusion. In general, higher CO2 pressures achieve greater CH4 recovery. The presence of even small amounts of N2 in the injection gas greatly reduces the CH4 recovered. CO2 at 500 to 800 psig [3447 to 5516 kPa] is shown to be capable of completely demethanating integral coal samples. This was confirmed by tests run on crushed cores. CO2 consumption by permanent adsorption is quite high vis-a-vis the CH4 recovered and may preclude its use as an enhanced-recovery energy process. Its primary function would appear to be as a means of safely primary function would appear to be as a means of safely demethanating coal beds before mining. Introduction This paper represents an extension of the work by Fulton, et al. to higher CO2 pressures. A rather complete literature review is presented in Ref. 1 and is not repeated here. This paper describes a series of laboratory tests run on Pittsburgh seam bituminous coal from West Virginia. Pittsburgh seam bituminous coal from West Virginia. Large coal cores were injected with CH4 to various equilibrium pressures and saturated with water. The CH4 then was vested and allowed to desorb at atmospheric pressure. This procedure is called "natural production." CO2 was injected until a predetermined production." CO2 was injected until a predetermined equilibrium pressure was reached. The pressure then was released either rapidly or slowly until atmospheric production was negligible. The gas quality and quantity production was negligible. The gas quality and quantity were analyzed and the CO2 adsorbed determined by material balance. Variations on this basic procedure included (1) the exclusion of the natural production cycle, (2) the speed of CO2 pressure drawdown, (3) the number of CO2 cycles that constitute the simulated recovery process, (4) the use of N2/CO2 mixtures as the injection gas, (5) variations in injection pressures from 200 to 800 psig [1379 to 5516 kPa], (6) subsequent exposure of crushed samples to CO2, and (7) the determination of the total CH4 in place (MIP) by successive injections of CO2 at 800 psig place (MIP) by successive injections of CO2 at 800 psig [5516 kPa] after the process cycles and regardless of the CO2 pressure employed in the latter. Experimental Procedure The experimental procedures and equipment descriptions are essentially the same as those described in Ref. 1. Briefly, the same size coal samples were used (3 1/2-in. [8.9-cm] diameter) and the pressure vessels were replaced with high-pressure stainless steel cylinders with O-ring seals. A new gas chromatograph was used and the collector system remained essentially unchanged. The coal was stored under water with a bactericide added, until cored. The cores were dried at 158 deg. F [70 deg. C] under vacuum for 30 to 70 days. The cores were subjected to CH4 adsorption until an equilibrium pressure was established at 200 psig [1379 kPa] (800 pressure was established at 200 psig [1379 kPa] (800 psig [5516 kPa] in the case of Sample 22). The cores psig [5516 kPa] in the case of Sample 22). The cores were permitted to imbibe water treated with a bactericide for several days, after which the immersed cores were subjected to a CH4 pressure equal to the adsorption pressure to achieve maximum water saturation. pressure to achieve maximum water saturation. The excess water was drained from the vessels and the porosity computed from the volume of water remaining porosity computed from the volume of water remaining and the assumption of 100% saturation of the coal fractures and matrix pores by the water. Following this the coal was allowed to desorb CH4 at atmospheric pressure until the produced CH4 was negligible. This lasted from 5 to 15 days and was proportional to the adsorption pressure. The natural production cycle was not included pressure. The natural production cycle was not included in Runs 14 to 16. After desorption, CO2 (CO2/N2 in the case of Run 20) was injected until some specified equilibrium pressure was established. These pressures, which are pressure was established. These pressures, which are listed in Table 1, ranged from 200 to 800 psig [1379 to 5516 kPa]. SPEJ P. 521
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
Analytically exact and continuous solutions are developed for the space-time relationships of a linear waterflood in a vertically stratified reservoir model. The solutions represent simple extensions of the analytical, but discrete, spatial relationships of Dykstra and Parsons to analytically continuous expressions. Explicit solutions for time are presented that permit the coupling of all instantaneous and cumulative performance parameters to a completely rational time basis.The continuous nature of the solutions permits unusual fluid behavior to be observed between successive bed breakthrough points. Although the model assumes pistonlike displacement, these novel phenomena do not appear to be artifacts of this limiting assumption.This work develops the concept of a bed property time that forms the basis for a generalized bed-ordering parameter. For the case of constant injection pressure, property time is shown to be identical to the real or process time. For the common case of constant overall injection rate, the customary use of property time concepts to determine real or process time is shown to be completely erroneous, yielding values that are incorrect both in magnitude and in trend.A bed flood-front passing phenomenon is presented that allows the flood fronts of "slower" beds initially to lead those of "faster" beds if specified constraints are satisfied. It is shown that these constraints can be satisfied for moderate bed-fluid property variations.The analytical nature of the solutions provides greater insight into the controlling factors of such processes. The use of real time as a process parameter provides a more realistic basis for comparative performance between floods under the same or different injection conditions. The relationship between injected PV and time can be used to extend the linear model to approximate predictions for stratified, nonlinear, pattern floods.
Air and water relative permeabilities have been measured for numerous samples of Pittsburgh and Pocahontas coals. Tests were performed under steady-state conditions for both drainage and imbibition cycles. Results indicate that the flow of gas is greatly reduced during the latter process, whereas during drainage it is largely undiminished over a wide water-saturation range. It is also shown that imbibition saturation distributions obtained from liquid.water imbibition as opposed to water·vapor adsorption produce gas permeability curves of radically different character. The effective permeabilities to both gas and water were significantly reduced with the application of overburden pressures in the range of a to 1, 000 psig, but the general shapes of the relative permeability curves remained the same.
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