PL176443B1 - Method of distributing carbon dioxide within a coal bed with simultaneous methane recovery therefrom - Google Patents

Abstract

A method for treating a mixture of gaseous fluids within a solid carbonaceous subterranean formation. In some embodiments, the invention provides for the disposal of a strongly adsorbing gaseous fluid within the formation. In other embodiments, the invention provides a means for fractionating a mixture of gaseous fluids within the formation. In still other embodiments, the invention provides for the recovery of a raffinate from the formation which is enriched in relatively weaker adsorbing gaseous fluids. In still other embodiments, the invention provides for the recovery of methane from the formation.

Description

The present invention relates to a method of distributing carbon dioxide in a coal bed and simultaneously recovering methane from the bed, which uses the ability of solid carbonic subterranean formations to selectively sorption gases to separate a mixture of gaseous fluids within the formation and to distribute the strongly adsorbed gases within the formation. A number of industrial processes produce waste streams containing various gaseous fluids. A growing concern is that some components of the exhaust streams can cause significant environmental problems and that therefore these streams should not be directed into the atmosphere. Carbon dioxide is a compound that is a component of many effluent streams released from industrial processes and whose release to the atmosphere is of increasing concern.

There are hypotheses that carbon dioxide released into the atmosphere acts as a greenhouse gas and that too much greenhouse gas concentration in the atmosphere will cause global warming. In response to these potential threats, a number of state authorities have either enacted or are planning to pass legislation to limit the amount of carbon dioxide that can be released into the atmosphere. These regulations can restrict many industries because combustion of any hydrocarbon fuel in air produces an exhaust stream containing carbon dioxide, nitrogen, and other gaseous combustion products.

The gas mixture that results from the combustion of hydrocarbons with oxygen or air is referred to herein as the exhaust gas. The chemical composition of the exhaust gas depends on many factors, including, but not limited to, the type of hydrocarbon burned, the ratio of oxygen to fuel in the combustion process, and the combustion temperature. In addition to carbon dioxide and nitrogen, the exhaust gas may contain compounds such as carbon monoxide, sulfur oxides, nitrogen oxides, and other components. The release of these compounds into the atmosphere is also subject to increasing public scrutiny and is the subject of an increasing number of state regulations.

Furthermore, in addition to being a product of hydrocarbon combustion, carbon dioxide can be produced by natural processes and released to the environment through processes other than combustion. For example, carbon dioxide is formed in thermal and biogenic processes that are believed to produce hydrocarbons such as oil

176 443 petroleum, natural gas or coal. Carbon dioxide is recovered with these hydrocarbons and released into the atmosphere at various post-production stages.

There are several types of commercial installations that can be used to remove carbon dioxide from gaseous streams. One of the most commonly used plants uses an amine-based selective absorption solution to remove carbon dioxide from the gaseous stream. Unfortunately, this type of plant cannot tolerate high levels of insoluble pollutants or sulfur oxides. Insoluble pollutants cause clogging, fouling, and erosion or corrosion in the process, while sulfur oxides such as sulfur dioxide (SO2) react irreversibly with the amine solution used in the plant to form non-regenerable by-products. Therefore, when insoluble impurities or sulfur oxides are present, additional steps are required in the process to remove sulfur oxides and insoluble impurities prior to the carbon dioxide removal step from the gaseous stream. These additional process steps complicate the installation and increase its cost.

The growing anxiety related to the release of carbon dioxide and other compounds into the atmosphere generates a need for methods of removing these compounds. Since the waste compounds often represent a major part of the effluent by volume, it is preferred that the removal methods use any larger effluent in order to improve overall process efficiency and / or facilitate the recovery of valuable product through the process and additionally provide for the removal of carbon dioxide present in the process.

Preferably, the methods should be capable of removing both carbon dioxide and other contaminants jointly, without requiring a process step to remove carbon dioxide and a different, separate process step to remove other contaminants such as sulfur oxides and nitrogen oxides.

When used in the description, the following terms have the following meanings:

(a) the adsorbant is that portion of the gaseous fluid mixture which is selectively adsorbed by the carbonaceous matter of the solid carbonaceous subterranean formation and which is recovered from the formation when the total pressure within the formation is lowered;

(b) cleavage planes, or cleavage pattern, means the natural fracture pattern within a solid carbonaceous subterranean formation;

(c) a coal bed, comprising one or more coal seams in fluid communication with each other;

(d) desorbing fluid, includes any fluid or mixture of fluids capable of causing methane to be desorbed from the solid carbonaceous subterranean formation;

(e) formation fracture pressure, or fracture pressure, means the pressure necessary to open a formation and to induce and propagate fractures along the formation;

(f) 'half the fracture length is the distance along the fracture from the wellbore to the end of the fracture;

(g) selective sorption, selective sorption, and selective sorption refer to processes that occur within a solid carbonaceous subterranean formation and that alter the relative proportions of gaseous fluid components. These processes can alter the relative proportions of gaseous fluid components through equilibrium separation, kinetic separation, steric separation, and / or any other physical or chemical process or combined process that within a solid carbonaceous subterranean formation will selectively alter the relative proportions of the components of the gaseous fluid mixture. Inside the formation, gases sorbed in the carbon matter of the formation will be enriched in relatively more strongly adsorbed liquid components;

(h) raffinate refers to that portion of the gaseous liquid mixture pumped into the solid carbonaceous subterranean formation which is not selectively sorbed in the formation;

(i) recovery means the controlled group and / or fluid disposition, such as storing fluid in tanks or distributing fluid through a pipeline. Recovery explicitly precludes venting the fluid to the atmosphere;

176 443 (j) formation pressure is the pressure of productive formation near the well opening while the well is closed. The formation pressure can vary along the formation. The formation pressure can vary along the formation. The formation pressure can also vary with time as fluid is pumped into the formation and as fluid exits the formation;

(k) carbonaceous subterranean formation means the substantially solid, carbonaceous matter containing methane and found below the earth's surface. It is assumed that these methane-containing materials were produced by thermal and biogenic degradation of organic matter. Solid carbonaceous subterranean formations include coal deposits and other carbon formations such as antrium, coal and Devonian shales. The formations to which the invention is applied are those that are depleted in recovered methane;

(l) Sorption refers to the process in which gas is trapped by a carbonaceous material such as carbon that contains micropores. The gas is trapped within the micropores of the carbonaceous material in a condensed or liquid-like phase, or the gas may be chemically bound to the carbonaceous material; and (m) the hole spacing or spacing is the straight-line distance between the individual wells, the production well, and the discharge well, the distance being measured from where the wells intersect the formation in question.

The essence of the invention

One object of the invention is a method of distributing carbon dioxide within a solid carbonaceous subterranean formation.

Another object of the invention is a method of distributing carbon dioxide within a solid carbonaceous subterranean formation while recovering methane from the formation.

The invention also relates to a method of distributing a strongly adsorbed fluid within a solid carbonaceous subterranean formation.

Yet another object of the invention is a method for fractionating a mixture of gaseous fluids within a solid carbonaceous subterranean formation.

Yet another object of the invention is a process for fractionating a mixture of gaseous fluids containing relatively more strongly adsorbed fluids and relatively less adsorbed fluids within a solid carbonaceous subterranean formation, and recovering a gaseous effluent enriched in relatively less adsorbed fluids from the formation.

The invention further relates to a method of using the recovered gaseous effluent enriched in relatively less adsorbed fluids to enhance methane recovery from a solid carbonaceous subterranean formation.

The invention also relates to a method of distributing unnecessary gaseous fluids inside a solid carbonaceous subterranean formation that has been at least partially depleted in recovered methane.

Yet another object of the invention is a method of distributing exhaust gas within a solid carbonaceous subterranean formation.

The following aspects of the invention meet the requirements of the above aspects of the invention.

The invention in its first form relates to a method which consists in that

(a) a gaseous fluid mixture containing a less adsorbed liquid component and a more strongly adsorbed liquid component is introduced into the coal seam, and

b) recovering raffinate enriched in a less adsorbed liquid component from the coal seam.

The subject of the invention in its second form is a method which consists in:

a) the formation is pumped through the discharge opening with a desorbing fluid containing carbon dioxide in the amount A, expressed as percentage by volume,

(b) recovered from the production well of the outlet stream containing methane;

c) monitoring the composition of the effluent produced in step b), and

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d) the recovery of the effluent produced in step b) is stopped when the percent by volume of carbon dioxide in the recovered effluent in step b) is greater than 0.5A.

According to a third embodiment, the method according to the invention is that

a) a desorbing fluid is pumped into the formation through the discharge opening, in which the volume ratio of carbon dioxide to other components of the pumped desorbing fluid is B,

(b) recover from the coal seam raffinate enriched in a less scrapped liquid component.

(c) the volume ratio of carbon dioxide to other components of the discharged decomposition fluid contained in the recovered production well outlet is monitored; and

d) recovery of the production well outlet stream is suspended when the volume ratio of carbon dioxide to other components of the pumped desorbing fluid in the outlet stream recovered from the production well is greater than 0.5B, and when at least 70% of the methane available through the production well has been recovered from the production well. production hole.

According to a fourth embodiment, the method according to the invention is that

a) a desorbing fluid is pumped into the subterranean formation through the discharge opening, in which the volume ratio of carbon dioxide to other components of the pumped desorbing fluid is B,

b) a gaseous effluent is recovering from the formation in which the volume ratio of carbon dioxide to other components of the formwork fluid to be pumped is less than B; and

c) the production of gaseous effluent from the formation is stopped when the volume ratio of carbon dioxide to other components of the pumped desorbing fluid within the gaseous effluent produced in step b) is greater than 0.5B.

According to a fifth embodiment of the method according to the invention, it consists in that

a) a gaseous fluid containing an undesirable component of the gaseous fluid is introduced into the formation to contain an undesirable component of the gaseous fluid through the formation; and

b) Maintaining the laying conditions within the formation such that at least 10 percent of the available saturation level of the undesirable component of the gaseous fluid remains adsorbed into the formation.

According to a sixth embodiment, the method according to the invention is that

a) a gaseous fluid is introduced into the coal seam, containing an undesirable component of the gaseous fluid,

b) the introduction of the gaseous fluid into the coal seam is stopped when the coal seam has been saturated to the desired degree with an undesirable component of the gaseous fluid.

According to a seventh aspect of the method according to the invention, a gaseous fluid is pumped into the coal seam containing an undesirable component of the gaseous fluid that is at least partially depleted in methane under such stowage conditions that will cause the undesirable component of the gaseous fluid to be sorbed in the coal seam and minimizing the release into the atmosphere of an undesirable fluid component.

The invention provides methods for utilizing large amounts of undesirable gaseous fluid within a solid carbonaceous subterranean formation.

In certain embodiments, fluids such as exhaust gas are contemplated, which may contain nitrogen oxide, sulfur oxides, carbon monoxide, and / or carbon dioxide for introduction into a solid subterranean carbon formation to enhance methane recovery from the formation.

The process of the invention can produce a nitrogen-enriched stream that can be used to enhance the recovery of methane from a solid carbonaceous subterranean formation without the need for separate plants for the separation of carbon dioxide and sulfur oxides.

176 443

A number of other features and advantages of the present invention will become readily apparent from the following detailed description of the invention, its specific embodiments set forth herein, the claims, and the accompanying drawings.

Explanation of figures in the drawings

Figure 1 is a graph of the total flow rate during gas production from a fully methane-saturated coal bed into which several different gas mixtures have been introduced.

Figure 2 is a graph of the cumulative predicted methane recovery from the coal bed of Figure 1.

Figure 3 is a graph of the predicted percentage by volume of methane present in the effluent stream recovered from the coal bed of Figure 1.

Figure 4 is a graph of the predicted percentage by volume of nitrogen present in the effluent stream recovered from the coal bed of Figure 1.

Figure 5 is a graph of the predicted percentage by volume of carbon dioxide present in the effluent stream recovered from the coal bed of Figure 1.

Figure 6 is a graph of the predicted coal bed methane recovery flow rates of Figure 1.

Figure 7 is a graph of the ratio of the total amount of recovered methane to the total amount of desorbing fluid injected into the coal bed of Figure 1.

Figure 8 is a plot of the cumulative volume of nitrogen recovered from a methane-depleted coal bed that is used to fractionate a gaseous fluid mixture containing 15 volume percent carbon dioxide and 85 volume percent nitrogen.

Figure 9 is a graph of the cumulative mixture of gaseous fluids being forced into the depleted carbon bed of Figure 8 over time.

Figure 10 is a graph of the nitrogen recovery flow rate from a depleted carbon bed of Figure 8.

Figure 11 is a graph of the total recovered gas flow rate over time from a fully methane saturated coal bed. The graph compares the total recovered gas flow when pure carbon dioxide is pumped into the bed with the recovery flow when a mixture of 70 volume percent carbon dioxide and 30 volume percent methane is pumped into the carbon bed.

Figure 12 is a graph of the predicted total methane volume to be recovered from the coal bed of Figure 11.

Figure 13 is a graph of the predicted amount of methane in volume percent that will be present in the effluent streams recovered from the coal bed of Figure 11.

Figure 14 is a graph of the predicted amount of carbon dioxide in percent by volume that will be present in the exhaust streams recovered from the coal bed of Figure 11.

Figure 15 is a graph of the predicted methane recovery rates for the coal bed of Figure 11.

Figure 16 is a graph of projected carbon dioxide recovery rates for the coal bed of Figure 11.

Figure 17 is a graph of the projected total production rate for the coal bed of Figure 11.

Figure 18 is a graph of the ratio of the predicted cumulative amount of recovered methane to the total amount of injected desorbing fluid for the coal bed of Figure 11.

Description of embodiments of the invention

Since this invention permits variation in a wide variety of forms, these are illustrated in the graphs, and specific variations will be described in detail herein.

176,443 of the invention. However, the present disclosure is to be understood as illustrative of the principles of the invention, and should not be construed as limiting the invention to the specific, illustrated variations thereof.

Solid, carbonaceous subterranean formations such as coal seams contain carbonaceous material. Carbonaceous matter includes parent rock having an extensive network of micropores and a fracture pattern that encompasses the parent rock and is commonly referred to as cleavage planes. The network of micropores creates a large internal surface to which gaseous fluids can adsorb. The method of the present invention takes advantage of the differences in the adsorption forces of various gaseous fluid molecules on the carbonaceous matter of the formation and the ability of large amounts of undesirable components of the gaseous fluid to sorption in the micropores of the carbon host rock.

Generally, a gaseous fluid particle which has a relatively stronger adsorptive force will be more selectively sorbed into the carbonaceous matter of the formation than a gaseous fluid particle which has a weaker adsorption force. The amount of any gaseous fluid that will adsorb in the carbonaceous matter of the formation depends in part on the relative adsorptive power of the gaseous fluid to the carbonaceous parent rock, the ability of the carbon parent rock to retain that gaseous fluid, the tendency of the particles of that gaseous fluid to chemically react with carbon matter, and hence chemisorption to matter as well as the actual pressure and temperature inside the formation.

An important factor in carrying out the process of the present invention is the relative adsorption forces of the components of the pumped gaseous fluid mixture to each other and to any fluids such as methane that may already be present in the formation.

For carbonaceous matter such as coal, the boiling point of a fluid at atmospheric pressure can be taken as indicative of the relative adsorptive power of the particles or compounds that make up the fluid. Table 1 shows the atmospheric boiling points of a number of common fluids.

Table 1

Compound / Molecule Boiling point Helium (He) -269 ° C Weaker adsorption power Hydrogen (H2) -253 ° C Nitrogen (N2) -196 ° C Carbon monoxide (CO) -192 ° C Argon (Ar) -186 ° C Oxygen (O2) -183 ° C Methane (CH4) -162 ° C Nitrogen oxide (NO) -151 ° C Xenon (Xe) -108 ° C Ethane (C2H6) -88 ^o C Carbon Dioxide (CO2) -78 ° C Sulfur hexafluoride (SF6) -64 ° C Hydrogen sulfide (H2S) -60 ° C Propane (C3H8) -42 ° C Sulfur Dioxide (SO2) -10 ° C Nitrogen Dioxide (NO2) 21 ° C Sulfur Trioxide (SO3) -44 ° C Stronger adsorption power

176 443

In general, it should be assumed that more strongly adsorbed fluids have higher boiling points, while less adsorbed fluids have relatively lower boiling points. Therefore, the relative adsorption force of one fluid component to another within the gas mixture and to other gaseous fluids within the formation can be determined by comparing their relative atmospheric pressure boiling points. For example, carbon dioxide, whose boiling point at atmospheric pressure is -78 ° C, adsorbs relatively more strongly to carbonaceous matter compared to methane or nitrogen, which have an atmospheric boiling point of -162 ° C -196 ° C, respectively. The relative boiling points of the fluid provide the individual skilled person with general information regarding the relative adsorption power of various gaseous fluids. However, if desired, the relative adsorption force of the various gaseous fluids to a particular carbonaceous matter of interest should be determined experimentally.

Further, the relative adsorption force of various gaseous fluids provides the individual skilled with general information regarding the location of the undesirable gaseous fluid within the solid carbonaceous subterranean formation. However, if necessary, the amount of the undesirable gaseous fluid that can adsorb to the particular gaseous matter should be determined experimentally. Experimental data should enable a more accurate prediction of the amount of gaseous fluid that may be available within the solid carbonaceous subterranean formation. If the chemistry of a particular component of the gaseous fluid in the carbonaceous matter of the formation is considered to be a significant factor, it should also be taken into account when determining the amount of undesirable gaseous fluid that may be available within the formation.

The gaseous fluid may be introduced into the formation either in gaseous or liquid form. A detailed description of suitable methods for pressing gaseous fluids according to the invention can be found in the description relating to the pressing of nitrogen-enriched raffinate, discussed below. Other suitable routes for introducing gaseous fluids into a solid carbonaceous subterranean formation are known to those skilled in the art. If the gaseous fluid containing carbon dioxide is pumped into a liquid state, it will typically be converted to a gaseous fluid within the formation. Alternatively, the gaseous fluid may be introduced into the formation as a supercritical fluid. Depending on the temperatures and pressures within the formation, the gaseous fluid may be maintained in the formation either in a surplus state, or it may become a liquid, a gaseous fluid, or coexist in a liquid state and vapor.

If the state of the gaseous fluid used is close to its critical temperature and pressure, it may be necessary to operate any production openings in such a way as to minimize precipitation and / or condensation inside the solid and liquid particle formation. Later on, a more detailed description of how to handle production openings in these types of situations is provided.

To recover methane in the subterranean formation, a desorbing fluid containing a highly adsorbed fluid is introduced into the solid carbonaceous subterranean formation through a delivery port fluidly connected to the formation, and the methane-containing effluent is recovered from one or more production wells. Preferably, the pressure opening penetrates the bed.

The desorbing fluid usually consists of carbon dioxide and other fluid components, for example nitrogen and / or methane. Since carbon dioxide is a highly adsorbed fluid, it will be more preferably adsorbed by the carbon matter of the formation than other less adsorbed fluids such as nitrogen and methane.

Methane is produced during the conversion of organic matter into carbon and other carbonaceous substances. Methane exists within the formation both as free gas in fractures and fractures in the formation and as adsorbed gas within the formation's carbonaceous matter.

The desorbing fluid containing carbon dioxide releases both free methane as well as the methane adsorbed within the formation. Release of methane ęαsdsorbzoaeegz

176,443 in carbon matter occurs as a result of lowering the partial pressure of methane inside the fractures, and therefore also carbon dioxide and other pumped desorbing fluids competitively sorb in the carbon matter of the formation.

The methane partial pressure inside the cracks is lowered due to the presence of the pumped desorbing fluid inside the cracks, near the methane sorption sites. As a result of lowering the partial pressure of methane inside the cracks, the methane adsorbed in the carbon matter will be desorbed from the matter and will diffuse into the cracks.

Competitive sorption in carbon matter of carbon dioxide and other pumped desorbing fluids will also desorb methane from the carbon matter into the fractures. Once the methane is inside the fractures, the pressure difference created between the formation and the production well and / or wells will cause the methane to move into the production well and / or the wells where it can be recovered.

Since methane is not as strongly adsorbed in carbon matter as carbon dioxide, it can move faster through a solid carbonaceous subterranean formation than more strongly adsorbed gaseous fluids.

Selective sorption inside the carbon matter of more strongly adsorbed fluids, such as carbon dioxide, fractionates the pumped desorbing fluid within the formation. More strongly adsorbed fluids will be more selectively adsorbed to the area of carbon matter around the discharge port into which the desorbing fluid is introduced. More strongly adsorbed fluids will continue sorption in the matter in this area, until the matter is saturated with more strongly adsorbed fluid. Relatively less adsorbed fluids will not adsorb so strongly in matter and thus will not move faster in the formation than more strongly adsorbed liquid ones.

Generally, as the desorbing fluid is forced into the formation, an area within the formation that is saturated with the more strongly adsorbed fluid moves continuously towards the production well or the production ports. Thus, it can be said that more strongly adsorbed fluids will create something that resembles a concentration front that moves inside the formation. As the desorbing fluid is forced into the formation, the front of concentrations is continuously moved from the delivery port to a lower pressure area within the formation, such as the production well.

At the forefront of the front, the concentration of fluids more strongly adsorbed to matter is small in relation to the concentration of fluids more strongly adsorbed inside or behind the front. Downstream, the relative concentration of the more strongly adsorbed fluids such as carbon dioxide that are adsorbed to the matter approaches a steady state value as the desorbing fluid is continuously forced into the formation through the delivery port.

The steady state value depends on a number of factors including: the relative adsorptive force of the fluids more strongly adsorbed to the carbonaceous matter compared to the adsorption force of other fluids within the formation, and the relative concentration of the more strongly adsorbed fluids contained in the pumped desorbing fluid entering the formation.

Since the components of the more strongly adsorbed fluid will be selectively sorbed by the formation, the carbon dioxide desorbing fluid can be pumped into the solid carbonaceous subterranean formation, while the effluent having a lower carbon dioxide percentage by volume is recovered from the production well. The percentage by volume of carbon dioxide contained in a mixture of gaseous fluids is expressed as the percentage by volume of A.

In addition, since the components of the more strongly adsorbed fluid may move more slowly through the formation than the components of the less adsorbed fluid, an outlet stream can be recovered from the production port where the volume ratio of carbon dioxide to other pumped components of the desorbing fluid is less than the volume ratio of carbon dioxide to other pumped components fluid components within the desorbing fluid entering the formation. The volume ratio of carbon dioxide to the other components of the pumped desorbing fluid is hereinafter sometimes referred to as the ratio B.

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One type of carbon dioxide-containing gaseous fluid that can be used in the present invention is exhaust gas. Typically, the volume ratio B of carbon dioxide to the other components of the pumped desorbing fluid in the exhaust gas is from 1/11 to 2/8. Another example of a gaseous fluid containing carbon dioxide that can be used in the present invention is a mixture of gaseous fluids that is discharged from the denitrification plant or from a membrane separator in which carbon dioxide is separated from the natural gas production stream. Typically, the discharged stream has a volume ratio B of carbon dioxide to methane and other gases from 1/1 to 95/5.

It can be assumed that the volume percent of carbon dioxide in the outlet stream recovered from the production well will be less than the volume percent of carbon dioxide in the pumped desorbing fluid entering the formation until the area of formation between the delivery port and the production port is saturated with the components of the more strongly adsorbed fluid. Furthermore, it can be assumed that the volume ratio of carbon dioxide to other components of the pumped desorbing fluid contained in the outlet stream recovered from the production well will be less than the volume ratio of carbon dioxide to other components of the pumped desorbing fluid inside the desorbing fluid introduced into the formation, until the formation area between the discharge port and the production port will be saturated with components of the more strongly adsorbed fluid.

Ideally, the solid carbonaceous subterranean formation is homogeneous and the carbon dioxide concentration front will move radially outward from the discharge port to the formation. However, there are few of these solid carbonaceous subterranean formations that exhibit this uniformity. Most formations have regions through which the pumped desorbing fluid will pass quickly. These so-called inclusions cover regions of relatively higher permeability compared to most carbon matter. Inclusions also include areas containing matter in which components of the desorbing fluid are difficult to adsorb. Examples of inclusion regions in which fluids are difficult to adsorb include sandstone, coal shale, and other similar materials known to those skilled in the art.

The pumped desorbing fluid that travels through the inclusions will at least partially bypass the carbonaceous material of the formation and is said to leak through the formation into the production well. Leakage will increase the relative + amount of desorbing fluid present in the effluent stream recovered in the production well.

Additionally, the pumped desorbing fluid that travels through the inclusions into the production port does not have as much contact with the carbonaceous matter of the formation as the pumped desorbing fluids that do not pass through the inclusions. Therefore, the pumped desorbing fluid that travels through the inclusions into the production port will not be fractionated as efficiently into its respective components. Consequently, the volume ratio of carbon dioxide to the other components of the pumped desorbing fluid within the recovered production well outlet stream will increase above what would be expected from an idealized formation, but this ratio will still be lowered compared to the initial B ratio in the pumped desorbing fluid. .

Selective sorption within the formation of the more strongly adsorbed fluid components, which causes the components of the more strongly adsorbed fluid to move more slowly through the formation than the components of the less adsorbed fluid, allowing the gray adsorbed fluids such as carbon dioxide to settle within the formation. Methods for distributing carbon dioxide and other more strongly adsorbed fluids within a solid carbonaceous subterranean formation are discussed in more detail below.

The ability of the solid carbonaceous subterranean formation to fractionate the pumped desorbing fluid, with most of the carbon dioxide subsequently reaching the production well and / or openings than methane and / or another fluid with weaker adsorptive forces, is the basis of a method for recovering the bulk of the methane from

176,443 solid carbonaceous subterranean formation with simultaneous distribution of carbon dioxide within the formation.

In carrying out the process in this manner, the ratio of carbon dioxide to the other pumped desorbing fluids within the recovered effluent is preferably controlled at the production well or wells using methods known to the individual skilled in the art, such as gas chromatography. This monitoring should provide a relative view of the movement of pumped desorbing fluids within the formation and answer the question of whether the formation begins to saturate with more strongly adsorbed fluids.

As discussed previously, the volume ratio of carbon dioxide to the other components of the pressable desorbing fluid within the recovered production port exit stream will be lowered relative to the volume ratio of carbon dioxide to other components of the pumped desorbing fluid within the pumped desorbing fluid entering the solid carbonaceous subterranean formation.

The ratio of carbon dioxide to other components of the pumped desorbing fluid recovered from the production well should rapidly increase as the carbon dioxide front reaches the production well. See, for example, the data in Figures 4, 5, 13 and 14. Also, most of the methane originally adsorbed inside the carbonaceous matter located along the flow path of the pumped desorbing fluid between the pressure port and the production port will be desorbed from the formation as the front advances. carbon dioxide concentration from the discharge port to the production port (i.e., the carbon material within the formation between the discharge port and the production port along the path of travel of the pumped desorbing fluid will release the methane contained therein).

As discussed previously, actual solid carbonaceous subterranean formations also have precipitates that can increase the volume percent of desorbing fluid contained in the effluent recovered from the formation. Additionally, the amount of pumped desorbing fluid needed to empty the formation may increase in proportion to the inclusions.

One method which the inventors believe can effectively reduce the amount of delamination that occurs within the formation is to periodically force a liquid, such as water, into the delivery port. The pumped water should selectively penetrate the areas of higher permeability. As liquid penetrates the regions of higher permeability, it will reduce the flow of desorbing fluids through these regions. This should result in a diversion of the pressurized desorbing fluid to the regions of lower permeability in order to increase vertical and spatial penetration within the formation. By redirecting the pumped desorbing fluids to areas of lower permeability, the time required for these fluids to move from the delivery port to the production port is increased. Due to the reversal of direction, the pumped desorbing fluid may also come into contact with more of the formation carbon matter, the volume percent of carbon dioxide in the recovered well outlet stream and the volume ratio of carbon dioxide to other components of the pumped desorbing fluid in the recovered well outlet stream can be reduced production.

Whether or not to cease recovery of the production well effluent depends in part on the percentage of available methane that is recovered from the production well drainage space. The available methane is that which is available for recovery from the production well. It should be noted that the methane available within the intensified recovery formation may not be depleted, while the methane available from a particular production well may be depleted. The amount of methane contained in a solid carbonaceous subterranean formation can be determined by methods known to the individual skilled in the art. Examples of intra-formation methane calculation methods are provided by Yee et al. In Gas Sorption on Coal and Measurement of Gas Content, Ch. 9, pp. 203-217, Hydrocarbon from Coal,

176,443 of the American Associacion of Petroleum Geologists (1993) hereby incorporated by reference. One skilled in the art who knows the amount of methane contained in the formation and the composition of the pumped desorbing fluid can calculate the amount of available methane that can be recovered from the formation.

The decision on whether to continue recovery of the production well effluent should also be made taking into account the effluent value. When determining the value of the effluent, it is important to consider the operating costs needed to further utilize the effluent. For example, if the effluent is sent to a natural gas pipeline, the effluent may need to be subjected to a process of reducing the percentage of inert gases therein to an acceptable level. The acceptable level of inert gas content in natural gas is determined by the technical requirements of the natural gas pipeline. If the value of the effluent is not large enough to justify further recovery of the effluent, then the recovery of the effluent should be discontinued or the method of recovery should be changed towards a composition change of the effluent which justifies its further recovery. A mining solid carbon underground formation containing methane may have multiple discharge and production wells. Due to the heterogeneity of most solid carbon subterranean formations, the carbon dioxide concentration front from one discharge well may reach the production well in front of the carbon dioxide concentration front from the second discharge port going to the same production well. This can lead to an increase in the volume ratio of carbon dioxide to other components of the pumped desorbing fluid in the outlet stream recovered from the production well, and to approach or exceed the initial ratio B before the formation between the delivery ports and the production well is released from the available methane.

As can be seen from the graphs of Figures 2, 3, 5-7 and 11-15, a substantial percentage of A of available methane can be recovered from the formation before the ratio of carbon dioxide to other components of the pumped desorbing fluid in the outlet stream recovered from the production well. reaches a value equal to the initial ratio B. It can be assumed that in some situations it is advantageous to discontinue recovery of the discharge stream from the production well when the ratio B is between 0.5 and 0.9 of the initial value of the ratio B. the desorbing fluid in the recovered exit stream is less than B, but a substantial percentage of the available methane has been recovered from the production well, discontinuing recovery of the production well exit stream may prove beneficial.

If the volume ratio of carbon dioxide to the other components of the pumped desorbing fluid in the outlet stream recovered from the production well is greater than the initial B ratio, and a substantial percentage of the available methane has been extracted from that well, it is preferable to discontinue recovery from that production well.

If the volume ratio of carbon dioxide to other components of the pumped desorbing fluid in the outlet stream recovered from the production well is greater than the initial B ratio but a substantial percentage of methane is still available for extraction from that production well, it is not preferred to interrupt recovery of the outlet stream from that production well. . However, the outflow of the outlet stream from this production well should be limited.

Restricting the outflow from the production well will increase the pressure inside the well. The increase in pressure near the production well will cause the pumped desorbing fluids to be directed into the formation space at a relatively lower pressure. This restriction should improve the emptying of the formation and also reduce leakage of the pumped desorbing fluid towards the production well from which the outflow has been restricted. Moreover, it can be assumed that as a result of pressure build-up in the formation around

176 443 of the production well, the selective adsorption in carbon matter in relation to methane should improve. It can be assumed that this will reduce the volume percent of carbon dioxide contained in the effluent stream recovered from the production well.

A number of methods can be used to limit the flow of the exit stream from the production well. One method uses the introduction of the flow restricting substance into a subterranean formation adjacent to the production well in which it is desired to limit the flow. Examples of substances useful in restricting the exit stream from the production well include carbon dioxide, acetone, diesel fuel, polymers, epoxies, surfactants, foam, cement, and mixtures thereof. The aforementioned substances reduce the flow of desorbing fluid within the formation by sealing or constricting the formation fracture system, thereby reducing the permeability of the formation spaces affected by these substances. In addition to the above-mentioned substances, any substance may additionally be used that causes swelling of the carbonaceous matter to reduce its permeability, or seals or constricts the formation fracture system.

Another way to limit the exit flow from the production orifice is to control the valve in fluid communication with the production orifice in a manner that restricts the exit flow from the production orifice. As with the previously described methods, limiting the flow of tar from the production well will increase the pressure within the well adjacent the formation and result in the previously discussed benefits which it is believed to be a result of the increase in pressure within the formation near the production well.

The above-discussed methods should help enable the recovery of the remaining available methane from the production well of interest.

Any amount of carbon dioxide recovered with the exhaust stream is readily separated from the methane and other fluids present in the nylated stream such as nitrogen. Examples of processes for the separation of carbon dioxide from the exhaust stream include:

- separation of carbon dioxide from the gas mixture using a membrane separator,

- separating carbon dioxide from the gas mixture using a separator employing an adsorption method, such as a molecular sieve pressure adsorption separator, and

- low-temperature separation of carbon dioxide from the gas mixture using a plant of the type used for nitrogen separation.

The carbon dioxide-containing stream, which is nitrous according to the above processes, usually also contains methane and / or nitrogen. If desired, the stream containing carbon dioxide can be reintroduced into the solid carbonaceous subterranean formation.

The inventors have discovered that in some cases it may be desirable to continue to extract the effluent from the production well and re-pump a significant portion of the effluent back into the formation. Examples of situations where this may be advantageous are where a significant amount of available methane is recovered from the production well, but the volume percent of carbon dioxide in the outlet stream is high. In such situations, the cost of separating inert gases such as carbon dioxide and nitrogen from methane using traditional separation methods can be prohibitive.

The inventors have discovered that in these situations it may be more advantageous to use the effluent to enhance methane recovery from other solid carbonaceous subterranean formations or different regions of the same solid carbonaceous subterranean formation. Advantageously, the formation into which the outlet stream is forced is still capable of adsorbing large amounts of carbon dioxide.

The re-pressed stream will fractionate in the formation. The carbon dioxide contained in the recycle stream will slowly move through the formation towards the production wells. As discussed earlier, the carbon dioxide will remove the methane from the formation. The methane contained in the re-pumped stream to blame

Move faster through the formation towards the production well. It can be assumed that the methane contained in the recycle stream will also assist in maintaining the formation reservoir pressure and thereby assist in recovering methane from the formation. Figures 11 through 18 are a graphical illustration of how, under certain circumstances, a gaseous fluid mixture containing methane and carbon dioxide can be advantageously used to recover methane from a solid carbonaceous subterranean formation.

Use of gaseous fluids

In this embodiment, the gaseous fluid that contains the undesirable component of the gaseous fluid is introduced into the solid carbonaceous subterranean formation. The gaseous fluid is introduced through the delivery port in fluid communication with the formation, preferably through the delivery port which penetrates the formation. The gaseous fluid is introduced into the formation at a pressure greater than the formation pressure and may be introduced into the formation in either a gaseous or a liquid state. Preferably, the gaseous fluid is introduced at a pressure lower than the fracture pressure of the formation. If the discharge pressure is too high and the formation ruptures, the pumped gaseous fluid may leak from the solid carbonaceous subterranean formation into the surrounding formations.

The gaseous fluid typically contains carbon dioxide and / or other components of the gaseous fluids that are relatively more strongly adsorbed to the carbonaceous matter of the formation than methane. Examples of other constituents of the gaseous fluid that the gaseous fluid feed typically contains include sulfur oxides, nitrogen oxides, and hydrogen sulfide. These relatively more strongly adsorbed gaseous fluids will be more preferably absorbed by the carbonaceous matter of the formation than any methane that may be present in the formation.

The exhaust gas is an example of a gaseous fluid that may be used in the present invention. The exhaust gas typically contains 10 to 25 volume percent carbon dioxide, about 75 to 90 volume percent nitrogen, and a low volume percent of nitrogen oxides and sulfur oxides. Another example of a gaseous fluid that may be used in the present invention is a mixture of gaseous fluids, which is a reject from the separator that separates carbon dioxide from the natural gas production stream. The reject stream typically contains from about 50 to 95 volume percent carbon dioxide with a residual gaseous fluid consisting primarily of methane. The rejected stream may also contain some hydrogen sulfide, nitrogen oxides, and sulfur oxides.

According to this embodiment, the solid carbonaceous subterranean formation that is used to remove undesirable constituents of the gaseous fluid is preferably depleted in recovered methane, preferably mostly recovered methane depleted, most preferably completely recovered methane depleted. A recovered methane-depleted formation is advantageously used because selective sorption in a solid carbonaceous subterranean formation of fluids such as carbon dioxide will be intensified within a formation that has an initial lower concentration of methane adsorbed in its carbonaceous material. Also, if the formation pressure is lowered and the formation is depleted of recovered methane, significant amounts of gaseous fluids that are relatively less adsorbed than methane can be efficiently distributed within the formation.

In other situations, it is advantageous to use a solid carbonaceous subterranean formation from which no methane has ever been extracted. Producing methane from such formations may not be attractive. Examples of such formations include formations with a low primary methane content and formations with a low permeability.

The recovered methane depleted formation still contains some methane but is present at such a concentration that it is uneconomical to recover from the formation. The recovered methane-depleted formation had at least 25 volume percent of the original methane removed. A formation largely depleted in recovered methane had at least 50 volume percent of the original methane removed. The completely depleted methane recovered formation had at least 70 volume percent of the original methane removed.

One way to recover methane from a formation is to lower the formation pressure. The reduction of pressure within the formation causes the methane to be desorbed from the carbonaceous matter and flow to the production well where it can be recovered. The extraction of methane from the coal seam through the production well using primary exhaustion will normally be discontinued when 25% to about 70% of the original methane is recovered on site. Typical pressures when production is withheld from such primary exhaust wells are between 689,476 Pascals (Pa) to about 2,068,427 Pa.

Methane can also be recovered from coal seams using improved recovery techniques. An example of an improved recovery technique that can effectively remove methane from a coal seam is the use of a nitrogen-enriched stream to desorb methane from a coal seam. For a coal seam to which improved nitrogen recovery techniques are applied, the percent recoverable seam methane depends primarily on the volume percent of nitrogen contained in the production stream recovered in the formation. Production wells are typically shut down when the nitrogen percentages become too high and / or the methane percentages become too low to justify further recovery. Using the current nitrogen / methane separation technology, the production well will typically be shut down when the volume percentage of methane in the recovered formation effluent is from 25% to about 50%. This is equivalent to recovering from 45% to about 70% of the original amount of methane inside the formation. It should be noted that as more effective methods of separating methane from nitrogen are discovered, the amount of methane that can be recovered from the formation will increase. When nitrogen has been used in the formation to enhance methane recovery from the formation, it may be advantageous to depressurize the formation prior to distributing the undesirable component of the gaseous fluid within the seam.

Another improved recovery technique by which methane can be efficiently recovered from a solid carbonaceous subterranean formation is enhanced recovery using carbon dioxide, which is discussed in more detail above.

As discussed earlier, more strongly adsorbed fluids will be more selectively sorbed in the region of carbon matter around the discharge port than relatively less adsorbed fluids. More strongly adsorbed fluids will continue to adsorb in the matter of the area until the matter is saturated with more strongly adsorbed fluid. Any relatively less adsorbed fluids that may be present within the formation will not adsorb as strongly into the matter and will therefore migrate within the formation to regions of lower pressure. In general, when gaseous fluid is pumped into the formation, the area within the formation that is saturated with the more strongly adsorbed fluid will continuously expand from the discharge port.

The saturation level of any component of the gaseous fluid in the carbon matter of the formation is dependent on a number of factors including: the relative adsorption strength of the fluids more strongly adsorbed to the carbon matter compared to the adsorption force of other fluids inside the formation, the relative concentration of the more strongly adsorbed fluids contained in the pumped gaseous fluid entering the formation, the ability of the carbonaceous matter to absorb a specific component of the gaseous fluid, and the pressure and temperature inside the formation.

For example, a typical San Juan Fruitland coal formation, which is completely depleted of methane, will sorb approximately 0.0246 normal cubic meters of gas per kilogram of carbon at 10342136 Pa and 46.1 ° C when the coal is subjected to rich saturation. a gaseous fluid containing 85 volume percent carbon dioxide and 15 volume percent nitrogen. The carbon sorbed phase will contain approximately 99 volume percent carbon dioxide and approximately 1 volume percent nitrogen. When coal is subjected to rich saturation with a gaseous fluid containing 50 volume percent carbon dioxide and 50 volume percent nitrogen under the same pressure and temperature conditions, the carbon will sorb approximately 0.0219 standard cubic meters of gas per kilogram of carbon. The sorbed phase will contain about 93 volume percent carbon dioxide and approximately 7 percent

176,443 nitrogen by volume. In a gaseous fluid containing 15 volume percent carbon dioxide and 85 volume percent nitrogen, at the same temperature and pressure, the carbon will sorb approximately 0.0153 normal cubic meters of gas per kilogram of carbon, while the sorbed phase will be approximately with 70 volume percent carbon dioxide and about 30 volume percent nitrogen. For a gaseous fluid containing 70 volume percent carbon dioxide and 30 volume percent methane, under the same temperature and pressure conditions, the carbon will sorb approximately 0.0233 normal cubic meters of gas per kilogram of carbon, with the sorbed phase containing approximately 86 volume percent of carbon dioxide carbon and about 14 volume percent methane. The saturation levels calculated above have been used with the assumption that the gaseous fluid is available in unlimited amounts in coal and that the components of the less adsorbed gaseous fluid flow continuously through the test area and are replaced by the fresh gaseous fluid, so that additional components of the gaseous fluid more strongly adsorbed, can be selectively sorbed by carbon. The enrichment of the sorbed phase with a strongly adsorbed fluid is the result of selective sorption, which takes place inside the solid, carbonaceous underground formation. Coal which is completely depleted of methane corresponds to a coal seam that contains less than approximately 10 volume percent of the original methane still within the seam.

The above-mentioned saturation levels for the particular undesirable component of the gaseous fluid are referred to herein as the available saturation levels. The available saturation levels for a particular undesirable component of gaseous fluid are calculated for a given temperature and pressure. The pressure and temperature, along with other parameters used to distribute the undesirable components of the gaseous fluid within the formation, are referred to herein as the deployment conditions. These placement conditions are varied to maximize the amount of undesirable gaseous fluid component absorbed by the formation. Typically, the deployment conditions are such that 10 to 99 volume percent of the undesirable component of the gaseous fluid introduced may be distributed within the formation. It may be assumed that in some instances more than 99 volume percent of the undesirable gaseous fluid component may be distributed within the formation. By distributing an undesirable component of the gaseous fluid within the formation, the release of undesirable components of the gaseous fluid into the atmosphere is prevented. Typically, maintaining the deployment condition requires only closing and / or adjusting the flow paths of the formation effluent to prevent an undesirable component of the gaseous fluid from being released from the formation while maintaining the pressure within the formation, preferably above the fracture pressure of the formation. In some cases, it may be advantageous to periodically drain the formation in order to maintain or increase the ability of the formation to sorb an undesirable gaseous fluid component. In some cases it may be beneficial to increase the temperature inside the formation. An example of a situation where increasing the temperature within the formation may prove beneficial is when an undesirable component of the gaseous fluid reacts chemically with the formation and the reaction becomes more favorable as temperatures within the formation increase.

For a given solid carbonaceous subterranean formation, the available saturation levels for a particular undesirable component of the gaseous fluid can be calculated using the expanded Langmuir adsorption isotherm model and the necessary empirical data for a specific formation. A description of the expanded Langmuir adsorption isotherm model and the method of its use to create a model similar to that used by the inventors is disclosed by LE Arri et al. In Modeling Coalbed Methane Production with Binary Gas Sorption, SPE 24363, pages 459-472, (1992), Society Publication of Petroleum Engineers, which is provided herein for reference.

It should be assumed that the available saturation levels can be achieved within a solid carbonaceous subterranean formation if there is a method of removing relatively less adsorbed fluid components from the formation so that more can be introduced into the formation.

176,443 more strongly adsorbed components. Additional, more strongly adsorbed components will continue to sorption in the formation until the available saturation levels within the sorbed matter phase are reached. One way to remove less adsorbed components from the formation may be through intermittent or intermittent venting from the less adsorbed fluid formation. Another way to remove the less adsorbed components from the formation may be to recover them through the production well. It is believed that the formation may be saturated with undesirable components of the gaseous fluid from 10 to 99 percent of the available saturation levels by operating in accordance with the present invention, preferably from 50 to 95 percent, more preferably from 70 to 90 percent.

In general, the pressure used in the present invention is selected to optimize the sorption in the carbonaceous matter of the undesirable gaseous fluid component formation. Typically, the higher pressure applied - more gas that carbonaceous matter can absorb.

When gaseous fluid is introduced into a solid carbonaceous subterranean formation, it is preferable to control the location within the formation of the undesirable components of the gaseous fluid, or the concentrations within the formation of the undesirable components of the gaseous fluid, and the ratio of the undesirable components of the gaseous fluid to other gaseous fluids being pumped. One of . Formation control methods are sampled from the control hole exit stream. Samples are analyzed using methods known to the individual skilled in the art such as gas chromatography. This inspection should provide relative clues as to how the pumped gaseous fluids move within the formation, and to what degree of saturation with undesirable gaseous fluid component the formation has been delivered.

If the undesirable component of the gaseous fluid is a fluid relatively more strongly adsorbed than the other components of the pumped gaseous fluid, then the volume ratio of the undesirable component of the gaseous fluid to the other delivered fluid components. gas inside the test outlet stream from the bore. control will be lowered relative to the volume ratio of the undesirable gaseous fluid component to the other pressurized gaseous fluid components within the pumped gaseous fluid entering the solid coal subterranean formation.

It can be assumed that this reduction in the ratio of undesirable components of the gaseous fluid to other pressurized components of the gaseous fluid is the result of the selective sorption of fluid components more strongly adsorbed within the carbon matter of the formation, such as carbon dioxide. It is believed that selective sorption causes the relatively more adsorbed fluid components to move slower through the formation than the less adsorbed fluid components. As discussed previously, when gaseous fluid is introduced into the formation, the area within the formation that is saturated with the more strongly absorbed fluid will expand starting from the discharge port. A more strongly adsorbed fluid creates a sort of concentration front that moves through the formation. As gaseous fluid is introduced into the formation, the concentration front is continuously moved from the discharge port towards the lower pressure areas within the formation. The enrichment of the test outlet stream with other pumped fluids will continue until the concentration front reaches the control hole.

The ratio of the undesirable component of the gaseous fluid to the other components of the pumped gaseous fluid collected at the inspection opening should increase rapidly as the front reaches the concentration of the formation area in which the inspection opening is drilled. Due to the heterogeneity of most solid carbonaceous subterranean formations, an undesirable component of the gaseous fluid may move unevenly within the formation. This can cause an undesirable component of the gaseous fluid to be unevenly distributed within the formation. Therefore, it is preferable to use not one but more orifices to control the formation.

In one embodiment of the invention, the introduction of gaseous fluid is continued until the desired degree of saturation of the formation with an undesirable component of the gaseous fluid. Any specialist will be able to determine the degree of saturation of individual areas inside

176 443 of the formation by taking a sample of the gaseous effluent from a control orifice that permeates the formation region.

The chemical composition of the sample taken, together with information on the pressure inside the formation near the control well, will enable any expert to determine the relative concentrations of each of the sorbed gaseous components inside the carbon matter from the formation area from which the sample was taken. This will allow any skilled person to determine whether an undesirable component of the pumped gaseous fluid has reached the area from which the sample was taken. It also allows the individual skilled in the art to assess the degree of saturation of the formation area with the undesirable component of the gaseous fluid. The desired degree of saturation within the formation is more fully detailed above in the description of the available saturation levels.

As discussed previously, if the undesirable component of the gaseous fluid is a relatively more strongly adsorbed fluid, venting the formation will adsorb the undesirable component of the gaseous fluid to the formation for any given deposition pressure. Venting may be accomplished through any opening that is in fluid communication with the formation. In the case of deaeration, it can be used continuously or intermittently and the deaeration can take place simultaneously with the pumping of the gaseous fluid or after the pumping of the gaseous fluid has ceased.

If components of the gaseous fluid such as hydrogen sulphide, sulfur oxides, and nitrogen oxides are released therefrom, it may be beneficial to reduce the pressure within the formation, suitable for desorbing carbon dioxide from the formation but not sufficient to cause desorption of hydrogen sulphide, nitrogen oxides and oxides from the carbonaceous matter. sulfur. This deaeration of the formation will allow larger amounts of more strongly adsorbed components, such as hydrogen sulphide and some nitrogen and sulfur oxides, to be distributed inside the formation.

The gaseous fluid may be pumped into the formation continuously or intermittently. The pumping of gaseous fluid is usually continued until the desired pressure is achieved. After the desired amount of gaseous fluid has been introduced into the formation, or when the formation has reached the desired pressure, the delivery port is closed and the formation is preferably maintained under suitable deployment conditions to contain the adsorbed, undesirable components of the gaseous fluid in the formation in an amount of 40 to 80 volume percent, preferably holding the formation. the undesirable constituents of the gaseous fluid adsorbed in the formation for at least one year after the gaseous fluids no longer enter the solid carbonaceous subterranean formation.

Conversely, the process of the invention is stopped after the formation has been saturated with the undesirable gaseous fluid to the desired extent. In carrying out the method of the invention, it is preferred that less than 50 percent by volume of the total amount of the undesirable component of the gaseous fluid introduced into the formation be released into the atmosphere, more preferably less than 10 percent by volume, most preferably less than one percent. The undesirable components of the gaseous fluid are preferably retained within the formation for at least one year, more preferably for at least five years, most preferably for at least ten years.

Fractionation of a mixture of gaseous fluids

In a further embodiment of the invention, the gaseous fluid mixture containing the liquid components relatively more strongly adsorbed and the liquid components relatively less adsorbed is introduced into the solid carbonaceous subterranean formation through an opening for fluid communication with the formation. The liquid components of the gas mixture, relatively more strongly adsorbed, will be selectively adsorbed in the carbon matter of the formation. The present invention uses this selective adsorption in the formation of more strongly adsorbed fluid components to provide a method for fractionating a mixture of gaseous fluids into a first fluid-enriched fraction relatively less adsorbed and a second fluid-enriched fraction relatively more strongly adsorbed. Examples of gaseous fluid mixtures that can be fractionated include: air, flue gases, gas mixtures produced by various industrial processes, and gas mixtures supplied from separators,

176,443 that separate, but are not limited to, non-flammable gases and condensing fluids from the natural gas production stream.

In this embodiment of the invention, the gaseous fluid mixture is typically introduced into the solid carbonaceous subterranean formation through the delivery port that penetrates the formation. Preferably the formation has already been depleted in methane recovered. The use of a depleted formation should serve to better fractionate the pumped gaseous fluid. The set pressure should serve to improve the fractionation of the gaseous fluid mixture into a fluid-enriched fraction relatively less adsorbed and a fluid-enriched fraction relatively more strongly adsorbed. Generally, the higher the pressure in the formation, the more gas can adsorb to the formation carbon matter.

A fraction enriched in less adsorbed fluids (sometimes referred to herein as raffinate) is typically extracted from the formation through the production well. The raffinate will be enriched with relatively less adsorbed fluids because relatively more strongly adsorbed fluids that are selectively adsorbed in carbon matter will move more slowly through the formation as previously described.

The raffinate is typically recovered from the formation until the raffinate concentration of the more strongly adsorbed fluids rises above an acceptable level. For a mixture of gaseous fluids containing carbon dioxide, the volume percent of carbon dioxide in the raffinate is preferably kept below 50 percent, more preferably below 2θ percent, most preferably below 5 percent. In some situations, it is possible to keep the percentage by volume of carbon dioxide in the raffinate below 1 percent.

Conversely, the injection of the gaseous fluid mixture is continued until the desired level of saturation of the formation is achieved. The desired adsorptive saturation of the formation can be determined using standard experiments. For example, the gaseous fluid mixture may be pressed until the raffinate has a volumetric ratio of relatively more strongly adsorbed fluids above an acceptable level as described above. Once the desired adsorptive saturation of the formation is achieved, the adsorptive capacity of the carbonaceous matter can be regenerated by reducing the overall pressure of the formation. The desorbed adsorbate, enriched in relatively more strongly adsorbed fluids, is released from the carbonaceous matter of the formation as the total pressure is lowered. The desorbed adsorbant may be recovered from the formation via the delivery port and / or the production well.

If the gaseous fluid mixture fractionated within the formation contains carbon dioxide, such as exhaust gas, the desorbed adsorbate will be carbon dioxide-enriched. If the gas mixture contains oxygen, for example air, the desorbed adsorbant will be oxygen-enriched. The recovered desorbed adsorbate can be forced back into the solid carbonaceous subterranean formation. For example, if a gaseous fluid mixture containing carbon dioxide is fractionated within a solid carbonaceous subterranean formation, the recovered desorbed adsorbant will be carbon dioxide-enriched. The recovered desorbed carbon dioxide-enriched adsorbant can be used to enhance methane recovery from the solid carbonaceous subterranean formation.

It may be desirable to maintain relatively strongly adsorbed fluids within the formation. In this situation, the formation pressure is not reduced and the adsorption capacity of the carbon matter of the formation is not regenerated. Conversely, the adsorption capacity of the carbon matter of the formation can be partially regenerated without lowering the total pressure to the point where undesirable components, if present, such as carbon dioxide, hydrogen sulfide or carbon monoxide, can be desorbed and released from the matter.

Generally, the pressure used in fractionating the gaseous fluid mixture is selected to optimize the fractionation of the fluid. Generally, the higher the pressure used, the more gas that can be adsorbed in the formation carbon. For a given system, faster raffinate removal from the system - higher volume percent within the raffinate of relatively strongly adsorbed fluids.

If the fractionated gas mixture of fluids contains a high percentage by volume of nitrogen, the obtained raffinate will be enriched with nitrogen. Air and exhaust gas are examples of gaseous fluid mixtures that contain a high volume percentage of nitrogen. Raffinate

The nitrogen-enriched nitrogen produced from these gaseous fluid mixtures can be used to enhance methane recovery from the solid carbonaceous subterranean formation. If flue gases are used, they should preferably be dehydrated before being injected into the formation. It is believed that the dehydration will reduce the potential corrosion problems that may arise in the pumping equipment and downhole as a result of the exhaust gas being pumped into the formation.

The nitrogen-enriched raffinate is pressed into a solid carbonaceous subterranean formation at a pressure above the formation pressure. Preferably, the nitrogen-enriched raffinate is pressed at a pressure greater than the formation formation pressure of from about 3,447,378 Pa to about 10,342,136 Pa. If the discharge pressure is lower than or equal to the formation pressure, the nitrogen enriched raffinate cannot normally be discharged because it cannot overcome the formation pressure. The nitrogen-enriched raffinate is preferably pressed at a pressure lower than the fracture pressure of the solid carbonaceous subterranean formation. If the pressure is too high and large fractures form in the formation, the pumped nitrogen-enriched raffinate may be lost and less methane may be produced.

However, based on studies of other types of vessels, it can be assumed that nitrogen-enriched raffinate may be pressed into the formation at a pressure in excess of the formation fracture pressure as long as the fractures created do not extend from the pressure port to the production port. In practice, stamping above the fracture pressure of the formation may be necessary to achieve adequate stamping and / or recovery rates to make the process economical, or in other cases it may be necessary to improve the bottom line when this can be done without reducing overall productivity. Generally, half the length of the slits formed within the fracture formations is less than about 20% to about 30% of the distance between the delivery port and the production port. Also preferably, the fractures created should be confined to the area of the formation.

Parameters important for methane recovery such as half the fracture length, fracture azimuth and height increase can be determined using known formation modeling techniques. Examples of techniques are discussed by John L. Gidley et al. In Recent Advances in Hydraulic Fracturing, Vol. 12, Society of Petroleum Engineers Monograph Series, 1989, pages 25-29 and 76-77, and by CL Schuster in Dedection Within the Wellbore of Seismic Signlas Created by Hydraulic Fracturing, article SPE 7448 presented at Society of Petroleum Engineers', Annual Technical Conference and Exhibition, Houston, Texas, 1978 October 1-3. In contrast, half the fracture length and the impact of their orientation can be estimated using a combination of pressure transient analysis and formation flow modeling as described in the article by N. Ali et al. SPE 22893, Injeption Above-Fracture-Parting Pressure Pilot, Valhal Field, Norway at the 69th Annual Technical Conference and Exhibition of the Society of Petroleum Engineers, Dallas, Texas, October 6-9, 1991. While it should be noted that the reference above describes how to improve crude oil recovery by pumping water above the formation fracture pressure, assume that the methods and solutions technically discussed in SPE 22893 can be adapted to improve methane recovery from a solid carbonaceous subterranean formation.

In general, the deeper the solid carbonaceous subterranean formation, the higher the necessary pressure to be pumped into the nitrogen-enriched raffinate formation. Typically, a discharge pressure of from about 2,757,903 Pa to 13,789,514 Pa will be adequate to convey the nitrogen-enriched raffinate to larger formations from which methane recovery is desired.

The nitrogen-enriched raffinate is forced into the solid carbonaceous subterranean formation through a discharge port in fluid communication with the formation. Preferably, the delivery port penetrates a methane containing formation, but the delivery port need not penetrate the formation as long as fluid communication exists between the formation and the pressure port. The delivery of the nitrogen-enriched raffinate can either be continuous or discontinuous. Discharge pressure can be kept constant or it can vary.

The methane-containing fluid is recovered from the production well in fluid communication with the formation. As with the discharge port, the production port is preferably

The formation penetrates a methane containing formation, but the production well need not penetrate the formation as long as fluid communication exists between the formation and the production well. The production well or wells are operated in the same way as traditional coal bed methane recovery wells. It may be desirable to minimize back pressure at a production well when recovering methane containing fluids from such production wells. The reduction of back pressure at the production well will be accompanied by the movement of fluids containing methane into the formation into the wellbore.

Preferably, the production well is operated so that the pressure at the production well, when located a wellbore in the vicinity of the methane producing formation, is less than the initial formation pressure. A located wellbore adjacent to the methane-producing formation is within the wellbore of the non-formation. The initial formation pressure is the formation pressure in the vicinity of the production well in question, in the period before the start of pumping nitrogen-enriched raffinate into the formation. The formation pressure may increase during pumping of the nitrogen-enriched raffinate, but it can be assumed that the pressure at the production well near the formation should preferably be kept below the initial formation pressure. This will improve fluid movement from the formation to the wellbore. More preferably, the pressure at the production well at a wellbore location near a methane producing formation should be less than about 2,757,903 Pa.

In some cases, back pressure downstream of the production wellbore may be advantageous, for example when it is desired to maintain a higher formation pressure in order to minimize the influx of water into the formation from surrounding aquifers. Such a water supply to the formation can reduce the rate of methane recovery as well as complicate the operation of the production well.

Another situation where it may be advantageous to maintain back pressure in the production wellbore is one that involves precipitation and / or condensation of solids and / or liquids within the formation near the wellbore or in the wellbore itself. Precipitation and / or condensation of solids or liquids in / or in the vicinity of the well can reduce the rate of methane recovery from the well. Examples of substances that may precipitate or condense in the vicinity of the wellbore and create a problem are waxes containing occluded oils that may break free from matter and move towards the production well. It can be assumed that the higher wellbore pressure of the production well located near the formation will minimize such precipitation and / or condensation of solids and liquids in or near the wellbore. Therefore, if precipitation and condensation in the wellbore are a problem, it may be advantageous to increase the pressure in the production wellbore to a value as high as practicable.

The timing and magnitude of the increase in methane recovery flow from the production well will depend on many factors including, for example, hole spacing, thickness of solid carbon subterranean formation, fracture porosity, pumping pressure and pumping rate, gas fluid composition, gas composition sorbed, formation pressure, formation permeability and total methane production prior to pumping nitrogen-enriched raffinate.

When the above parameters are kept constant, a shorter distance between the discharge and production wells will result in a faster perceived production well response (both an increase in methane recovery rate and a shorter time between before the nitrogen-enriched pressed raffinate appears at the production well) than the response which is the case with the discharge and production port separated by a greater distance. As holes are opened, the need for a rapid increase in methane production rate must be offset again by other factors such as nitrogen breakthrough earlier than when a reduced hole spacing is used and the amount of nitrogen-rich raffinate used to desorb the methane from the formation for each seeding.

If desired, the methane produced in accordance with this invention can be separated from accompanying gases such as nitrogen or mixtures of nitrogen and any other gas

176,443 or gases that may have been injected into or extracted from a solid carbonaceous subterranean formation. Such production accompanying gases will of course include any gases that occur naturally in solid carbonaceous subterranean formations along with methane. These gases, which occur naturally together with methane, are commonly referred to as coal bed methane. These naturally occurring gases can contain, for example, hydrogen sulfide, carbon dioxide, ethane, propane, butane, and heavier hydrocarbons in smaller amounts. If desired, the methane produced in accordance with this invention can be mixed with methane from other sources that contains relatively less impurities.

Example 1.

This example shows the predicted coal bed response when various desorbing fluids are pressed into the coal bed to enhance methane recovery from the coal bed. In this example, pressing starts after one year. In this example, all the desorbing fluids are pressed into the coal bed at a delivery pressure of 13,789,514 Pa. The formwork fluids pumped into the formation include:

- pure nitrogen,

- exhaust gas containing 85 percent by volume nitrogen and 15 percent by volume carbon dioxide,

- equilibrium mixture of carbon dioxide and nitrogen,

a desorbing fluid containing 85 percent by volume carbon dioxide and 15 percent by volume nitrogen, and

- pure carbon dioxide.

The data shown in Figures 1 to 7 are derived from a model designed to describe a hypothetical carbon deposit which is 3.05 meters thick and which is completely homogeneous in both directions, both vertically and horizontally. The data presented in the graphs are corrected to a temperature of 15.6 ° C and a pressure of 101353 Pa. The hypothetical coal deposit has the following characteristics:

permeability = 10 mD, porosity = 0.5%, the formation pressure is 10342136 Pa, before the commencement of pumping of the formwork fluid, and the bed temperature is 46.1 ° C.

Coalbed methane is saturated and the drain region through the opening production is 186,155 m ² area of the formation. The model assumes that the production borehole is surrounded by four discharge holes that are arranged in a five-point formation. It is assumed that each delivery port acts the same on the production port and thus a quarter of the response in the production port is related to each discharge port. The total amount of desorbing fluid pumped into the formation drained through the production well comes from the four discharge ports. Each delivery port contributes a quarter of the total amount of desorbing fluid pumped. Figures 1 to 7 show the predicted recovered gas volumetric flow rate in m ³ x 103 / day (in thousand standard cubic meters per day) and the projected total gas production in m3 x 10 ⁶ (in million standard cubic meters).

The model used was developed using a two-dimensional nirial equation of state. Description of viral state equations and how to apply them to. creating a model similar to one used by the inventors is discussed in DeGance, Multicomponent high-pressure adsorption equilibrium on carbon substrates: theory and data '', Fluid Phase Equilibria, 78, pp. 99-137, (1992), E ^ ewer Science Publishers BV, Amsterdam, incorporated herein by reference.

As can be seen from the graphs of Figs. 1 to 5, the volume percent of carbon dioxide in the production well recovered fluid is kept below the volume percent of carbon dioxide contained in the pumped desorbing fluid for the entire period after the start of delivery of the desorbing fluid. The percentage covered24

The volume of carbon dioxide in the recovered outlet stream begins to increase at substantially the same time as the volume percent of methane in the recovered outlet stream begins to decrease. As can be seen from the graphs of Figures 2 to 5, a substantial percentage of the available methane contained in the formation will be recovered over a period of time the volume percent of carbon dioxide in the recovered effluent increases above the volume percent of carbon dioxide in the pumped desorbing fluid. Also, since methods are available to economically separate carbon dioxide from methane, nitrogen, and other gases, carbon dioxide can be separated from the recovered production well off-stream and pumped back into the coal bed and / or other nearby coal bed.

Figures 1 to 7 also show the substantial percentage of available methane that can be recovered from the area drained through the production well before the volume ratio of carbon dioxide to other components of the pumped desorbing fluid contained in the outlet stream recovered from the production well reaches the volume ratio of the dioxide by volume. carbon to other components of the pumped desorbing fluid contained in the pumped desorbing fluid.

It should be noted that since the model in the above example and the implemented example are idealized, they cannot take into account the heterogeneity present in the actual solid carbonaceous subterranean formation. Thus, this model and the model described in Examples 2 and 3 cannot predict leakage that may occur within the formation. However, the disclosed examples, together with the previous discussion on counteracting delamination within the formation, will assist those skilled in the art in practicing the invention.

Example 2.

This example illustrates the expected reaction of coal bed desorbing fluids when carbon dioxide-containing desorbing fluids are pressed into the coal bed to improve methane recovery from the coal bed. In this example, pumping of the desorbing fluids began after four years of primary exhaustion. In this example, all the desorbing fluids are forced into the carbon bed at a delivery pressure of 13789514 Pa through a delivery port having a skin nature of -3. The well has a head pressure of 689,476 Pa and a skin feel of -3. Epidermis is a measure of the permeability of the formation near the wellbore. Positive skin indicates damage to the formation near the wellbore, and negative skin indicates stimulation of the formation near the wellbore. The desorbing fluids pumped into the formation include: pure carbon dioxide, and a desorbing fluid containing 70 volume percent carbon dioxide and 30 volume percent methane.

The data in Figures 11 to 18 have been taken from a model that was developed to describe a hypothetical coal bed which is 15.24 m thick and which is completely homogeneous in both directions, both vertically and horizontally. The data presented in the graphs are corrected to a temperature of 15.6 ° C and a pressure of 101353 Pa. The hypothetical coal deposit has the following characteristics:

permeability = 5 mD, the formation pressure is 10342136 Pa, before pumping the desorbing fluid, and the bed temperature = 46.1 ° C.

Coalbed methane is saturated and the drain region through the opening production is 647,497 m ² area of the formation. The model assumes that the production borehole is surrounded by four discharge holes that are arranged in a five-point formation. It is assumed that · each discharge port acts the same on the production port and thus a quarter of the reaction in the production port is related to each discharge port. The total amount of desorbing fluid pumped into the formation drained through the production well

176 443 comes from four discharge ports. Each delivery opening contributes a quarter of the total amount of desorbing fluid pumped.

The model used was developed using the extended model of Langmuir adsorption isotherms. A description of the extended Langmuir adsorption isotherm model and how it can be used to create a model similar to that used by the inventors is described by LE Arri et al. In Modeling Coalbed Methane Production with Binary Gas Sorption, SPE 24363, pp. 459-472 (1992), Society Publication of Petroleum Engineers, incorporated herein as a reference.

The example illustrates that in certain situations, as should be known to the individual skilled in the previous disclosure, a desorbing fluid containing carbon dioxide and methane is preferably used to recover methane from a solid carbonaceous subterranean formation, especially if the cost of separating methane from the recovered coal stream is economical. unprofitable. In this situation, the effluent is forced back into the formation which adsorbs the carbon dioxide component of the stream and allows the methane to flow to the production well where it is recovered.

Example 3.

This example uses the same type of modeling techniques and the same parameters as used in Example 2. However, this example uses an unsaturated carbon bed, and a mixture of gaseous fluids containing 15 volume percent carbon dioxide and 85 volume percent nitrogen is pumped into the carbon bed. . Pumping of gaseous liquids begins at zero point in time. The graphs of Figures 8-10 related to the example show that a solid carbonaceous subterranean formation can efficiently provide a nitrogen-enriched effluent when a gaseous fluid mixture containing nitrogen and carbon dioxide is introduced into the formation. The model was constructed so that the volume percent of nitrogen in the recovered exhaust stream should be 100% for the entire period shown in Figures 8 to 10, and that the volume percent of carbon dioxide in the recovered exhaust stream should not increase above 0.01% for the entire period. shown in the graphs of figures 8 to 10.

It can be assumed that the solid carbonaceous subterranean formation will also provide a nitrogen-enriched effluent when air is introduced into the formation through the delivery port and removed through the production port.

From the above description, it can be seen that a number of changes, variations and modifications will be apparent to those skilled in the art. Therefore, this description is intended as an illustration only and to teach those skilled in the art to practice the invention. Various changes can be made and the materials described in the application can be replaced. For example, it can be assumed that the gaseous fluid that will be chemisorbed into the carbon matter of the formation can be placed in the formation in a similar manner as disclosed for highly adsorbed fluid dispersing within the formation.

Therefore, it is judged that various changes, modifications, variations etc. can be made without prejudice to the spirit and scope of the invention as defined in the appended claims. Of course, all such modifications are intended to be covered by the appended claims.

176 443

Total <v • H

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0>

4-1 fO c

Start of pressing

FIG. 2

Pure nitrogen

Exhaust (85/15)

Equimolar mixture (50/50) Enriched carbon dioxide (15/85) Pure carbon dioxide

Primary, pressure drainage <u <D C Ή N C υ oj> i χ 3 Li w c <α> ία Snu 3 ό o ω o £

Launch of Pure Nitrogen Discharge Exhaust (85/15)

Equimolar mixture (50/50) CO ₂ - enriched (15/85) Pure carbon dioxide Primary scavenging

176 443

Content

Start of pressing

Pure nitrogen

Exhaust (85/15)

Equimolar mixture (50/50) CO, - enriched (15/85)

Start of pressing

Pure nitrogen

Exhaust (85/15)

Equimolar mixture (50/50) CO ₂ - enriched (15/85)

176 443 • at • Ul

ABOUT

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IB

Start of pressing

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Exhaust (85/15)

Equimolar mixture (50/50) CO ₂ - enriched (15/85) Pure carbon dioxide

Launch of Pure Nitrogen Discharge Exhaust (85/15)

Equimolar mixture (50/50) CO ₂ - enriched (15/85)

Pure carbon dioxide

176 443

FIG. 7

Equimolar mixture (50/50) C0 ₂ - enriched (15/85)

Pure carbon dioxide

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Start pumping the mixture

15% CO ₂ /85% Ni

176 443

FIG. 9

pressing the mixture

15% CO ₂ /85% N ₂

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FIG. 10

TIME, YEARS

Start pumping the mixture

15% CO ₂ /85% N ₂

176 443

FIG. II

Complete

Total flow rate

The gaseous fluid used containing 100% CO; The gaseous fluid used contains 70% CO ₂ /30% CH ₄

The gaseous fluid used containing 100% CO _; The gas fluid used containing 70% CO ₂ /30% CH ₄

176 443

The gaseous fluid used containing 100% CO ₂ The gaseous fluid used containing 70% CO ₂ /30% CH ₍ ^u c □ u 3 <3 -H • tn Λί coc «o

U H> 1'H Μ Η N E (0 u u a 3 O O M (0 3 4J Ν Ό 3 W

The gaseous fluid used with 100% CO _2. The gaseous fluid used with 70% CO ₂ /30% CH.

176 443

and -Γ-Ι about e Ό 0 3 3 \ • H 3 3 C S -H ABOUT 4) rM 3 Ή -N CL <n C fl> 0,> i (0 X 4J N N + J Ii H 3 UJ ε with α o ε

FIG. 15

The gaseous fluid used with 100% CO ₂ The gaseous fluid used with 70% CO ₂ /30% CH ₄

The gaseous fluid used with 100% CO ₂ The gaseous fluid used with 70% CO ₂ /30% CH ₄

176 443

Summarized

FIG. 17

The gaseous fluid used containing 100% CO; The gas fluid used containing 70% CO / 30% CH ₍

FIG. I8

about σ σ> c about N c υ > 1 44 3 Μ Ό n c flj '01 > (Π £ o N 4-> 3 Ό 0 en -η About £

The gaseous fluid used containing 100% CO; Gas fluid used containing 70% CO ₂ /30% CH,

Publishing Department of the UP RP. Circulation of 70 copies. Price PLN 6.00.

Claims (16)

Patent claims 1. A method of distributing carbon dioxide in a coal bed and simultaneously recovering methane from a solid carbonaceous subterranean formation penetrated through a discharge and production wells, characterized in that a) 'the desorbing fluid is pressed into the formation through the discharge opening, the volume ratio of carbon dioxide to other components of the pumped desorbing fluid being B, b) a gaseous effluent containing methane and carbon dioxide is released from the formation through the production port in which the volume ratio of carbon dioxide to the other components of the displaced desorbing fluid is less than B; and c) the production of gaseous effluent from the formation is stopped when the volume ratio of carbon dioxide to other components of the pumped desorbing fluid within the gaseous effluent produced in step b) is greater than 0.5B. 2. The method according to p. The process of claim 1, wherein the desorbing fluid is forced into a solid carbonaceous subterranean formation containing at least one carbon seam. 3. The method according to p. The process of claim 1, wherein the exhaust gas containing desorbing fluid is pumped. 4. The method according to p. The process of claim 1, wherein the desorbing fluid comprises greater than forty-nine volume percent carbon dioxide. 5. The method according to p. The process of claim 4, wherein the desorbing fluid comprises methane and carbon dioxide. 6. A method of distributing carbon dioxide in a coal bed and simultaneously recovering methane from a solid carbonaceous subterranean formation, characterized by (a) a gaseous fluid mixture containing a less adsorbed liquid component and a more strongly adsorbed liquid component is introduced into the coal seam, and b) recovering raffinate enriched in a less adsorbed liquid component from the coal seam. 7. The method according to p. The process of claim 6, characterized in that the total pressure in the coal seam is determined during step b), and furthermore c) the total pressure in the carbon bed is lowered to cause desorption from the carbon bed of an adsorbate enriched in more strongly adsorbed liquid components, and (d) at least part of the desorbed adsorbate is removed from the carbon seam. 8. The method according to p. 6. The method of claim 6, additionally in step c) pressing the raffinate into the second coal seam through the discharge port, and in a step (d) recover methane from the second coal seam. 9. The method according to p. The method of claim 6, characterized in that to the coal seam in step (a) a mixture of air-blowing gas is introduced and that the nitrogen-enriched raffinate is recovered from the coal seam. 10. The method according to p. The process of claim 6, wherein the methane-containing raffinate is recovered in step b). 11. The method according to p. The process of claim 6, characterized in that a mixture of gaseous fluids containing methane and carbon dioxide is introduced into the coal seam in step a). 176 443 12. A method of distributing an undesirable component of carbon dioxide in a coal bed and simultaneously recovering methane from a solid carbonaceous subterranean formation, characterized by a) introducing a gaseous fluid containing an undesirable component of the gaseous fluid into the formation for sorption by the formation of an undesirable component of the gaseous fluid; and b) Maintaining the laying conditions within the formation such that at least 10 percent of the available saturation level of the undesirable component of the gaseous fluid remains adsorbed into the formation. 13. The method according to p. The method of claim 12, wherein from about 40 to about 80 volume percent of the undesirable gaseous fluid component adsorbed in the formation is adsorbed into the formation after one year. 14. The method according to p. The process of claim 12, wherein the solid carbonaceous subterranean formation is depleted in recovered methane. 15. The method according to p. The process of claim 12, wherein the undesirable component of the gaseous fluid comprises carbon dioxide. 16. The method according to p. A process as claimed in claim 12, characterized in that in step a), a gaseous fluid containing exhaust gas is introduced, and that the undesirable component of the gaseous fluid adsorbed in the formation is selected from the group consisting of nitrogen oxides, sulfur oxides and mixtures thereof.