CA2176588C

CA2176588C - Method for disposing carbon dioxide in a coalbed and simultaneously recovering methane from the coalbed

Info

Publication number: CA2176588C
Application number: CA002176588A
Authority: CA
Inventors: Joseph J. Chaback; Dan Yee; Richard F. Volz, Jr.; John P. Seidle; Rajen Puri
Original assignee: BP Corp North America Inc
Current assignee: BP Corp North America Inc
Priority date: 1994-04-01
Filing date: 1995-03-24
Publication date: 2000-10-03
Anticipated expiration: 2015-03-24
Also published as: CA2176588A1; CN1135782A; PL316630A1; PL176443B1; AU692248B2; WO1995027123A1; CN1091832C; AU2193895A

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

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PCTfUS95103689 METHOD FOR DISPOSING CARBON DIOXIDE IN A COALBED AND SIMULTANEOUSLY RECOVERING
METHANE FROM THE COALBED
__ F1,~1 OF THE INVENTION
The present invention relates. to methods which utilize a solid carbonaceous subterranean formation's ability to preferentially sorb gases to 1 0 fractionate a mixture of gaseous fluids within the formation and to dispose of strongly adsorbing gases within the formation.
~yUND OF THE INVENTION
Numerous industrial processes discharge streams which contain a 1 5 mixture of various gaseous fluids. There is increasing concern that some of the constituents of the effluent streams may cause significant environmental problems, and that these streams therefore should not be released into the atmosphere. Carbon dioxide is a coompound which is a constituent of many of the effluent streams released from lindustrial processes and whose release into 20 the atmosphere is causing increasing concern.
R is hypothesized that carbon dioxide released into the atmosphere acts as a green-house gas and that too high a concentration of green-house gases in the atmosphere will cause global warming. In response to this potential threat, many governmental bodies have either enacted or plan to enact 25 regulations limiting the quantity of carbon dioxide which can be released into the atmosphere. These regulation s can hamper many industries because the combustion of virtually any hydrocarbon fuel with sir produces an effluent containing carbon dioxide, nitrogen, and other gaseous combustion products.
The mixture of gases which n3sutts from the combustion of a hydrocarbon 30 with oxygen or air is hereinafter referred to as "flue gas." The chemical composition of flue gas depends on many variables, including but not limited to, the combusted hydrocarbon, the combustion process oxygen-to-fuel ratio, and the combustion temperature. In addition to carbon dioxide and nitrogen, flue gas may contain compounds such ass carbon monoxide, oxides of sulfur, oxides 35 of nitrogen, and other constituents. The release of these compounds to the W0 95/27123 2 PCT/US95l03689 .
atmosphere also is coming under increasing public scrutiny and is the subject of increasing govemrnentai regulation.
In addition to being a hydrocarbon. combustion product, carbon dioxide can be produced by natural processes and released to the environment during a non-combustion process. For example, carbon dioxide is produced by the thermal and biogenic processes which are believed to form hydrocarbons such as oil, natural gas, or coal. Carbon dioxide often is recovered with these hydrocarbons and released to the atmosphere by various post-production steps.
There are several types of commercially available systems which may be used for removing carbon dioxide from gas streams. One of the most commonly-used systems utilizes a selective amine absorption solution to strip the carbon dioxide from the gas stream. Unfortunately, this type of system will not tolerate high levels of particuiates or oxides of sulfur. Particulates cause plugging, contamination, and erosion or corrosion of the treating process, while oxides of sulfur, such as sulfur dioxide (S02), react irreversibly with the amine solution utilized in the system to form non-regenerabie by-products.
Therefore, if particulates or oxides of sulfur are present, extra process steps are required to remove the oxides of sulfur and particulates prior.to stripping the carbon dioxide from a gas stream. These extra process steps add complexity and cost to the system.
The increasing concern over the atmospheric release of carbon dioxide and other compounds demands methods by which to dispose of the compounds. Because the waste compounds often are a constituent of a volumetrically larger effluent stream, it is preferred that the disposal methods somehow utilize the larger effluent streams to enhance the efficiency of the overall process andlor to facilitate the recovery of a valuable product using the process in addition to providing for the disposal of carbon dioxide contained therein.
Preferably, the methods also should be capable of disposing of both carbon dioxide and other contaminants together, without the need to use a process step to dispose of carbon dioxide and another separate process step to dispose of other contaminants, such as oxides of sulfur and oxides of nitrogen.
As used herein, the following terms shall have the following meanings:
(a) 'adsorbate' is that portion of a mixture of gaseous fluids which is preferentially adsorbed by a carbonaceous matrix of the solid .

~~~s~ss W0 95127123 3 PCTlITS95103689 carbonaceous subterranean formation and which is recovered from the formation when the total pressure within the formation is reduced;
(bj "cleats' or 'cleat system" is the natural system of fractures within a solid carbonaceous subterranean formation;
(c) a 'coalbed" comprises one or more coal seams in fluid communication with each other;
(d) ~desorbing fluid" includes any fluid or mixture of fluids which is capable of causing methane to desorb from a solid carbonaceous subterranean formation;
1 0 (e) "formation parting pressure" and "parsing pressure' mean the pressure needed to open a foirmation and propagate an induced fracture through the formation;
(f) "fracture half-length' is the distance, measured along the fracture, from the wellbore to the fracture tip;
(g) 'preferentially sorbing", 'preferentially sorbs', and "preferential sorption" refer to processes which occur within a solid carbonaceous subterranean formation that alter the relative proportions of the components of a gaseous fluid. These processes may after the relative proportions of the components of a gaseous.fiuud by equilibrium separation, kinetic separation, steric separation, andlor any other physical or chemical processes or combination of processes which within a solid carbonaceous subterranean formation will selectively alter the relative proportions of the components of a mixture of gaseou> fluids. Within the formation, the gases sorbed to the carbonaceous malter?al of the formation will be enriched in relatively stronger adsorbing fluid components;
(h) "raffrnate" refers to that portion of a mixture of gaseous fluids injected into a solid carbonaceous subterranean formation which is not preferentially sorbed by the formation;
(i) 'recovering' means a controlled collection andlor 3 0 disposition of a fluid, such as storing the fluid in a tank or distributing the fluid through a pipeline. "Recovering' spec:i~caliy excludes venting the fluid into the atmosphere;
(j) "reservoir pressure' means the pressure of a productive formation near a well during shut-in of that well. The reservoir pressure can vary throughout the formation. Al;ao, the reservoir pressure of the formation may change over time as desorbing fluid is injected into the formation and fluids are produced from the formation;
(k) "solid carbonaceous subterranean formation" refers to any substantially solid carbonaceous, methane-containing material located below the surface of the earth. It is believed that these methane-containing materials are produced by the therm8l and biogenic degradation of organic matter. Solid carbonaceous subterranean formations include but are not limited to coalbeds and other carbonaceous formations such as antrium, carbonaceous, and devonian shales. The. formations utilized by the invention include formations which are depleted of recoverable methane;
(I) 'sorption" refers to a process by which a gas is held by a carbonaceous material, such as coal, which contains micropores. The gas is held on the carbonaceous material in a condensed or liquid-like phase within the micropores, or the gas may be chemically bound to the carbonaceous 1 5 material; and (m) "well spaang' or "spacing" is the straight-line distance between the individual wellbores of a production well and an injection well.
The distance is measured from where the wellbores intercept the formation of interest.
SUMMARY OF THE INVENTION
One object of this invention is to provide a method for fractionating a mixture of gaseous fluids within a solid carbonaceous subterranean formation.
Another object of the invention is to provide a method for disposing of a strongly adsorbing fluid within a solid carbonaceous subterranean formation.
Yet another object of the invention is to provide a method for disposing of carbon dioxide within a solid carbonaceous subterranean formation.
Still another object of the invention is to provide a method for disposing of carbon dioxide within a solid carbonaceous subterranean formation while 3 0 simultaneously recovering methane from the formation.
Another object of the invention is to provide a method for fractionating a mixture of gaseous fluids containing relatively stronger adsorbing fluids and relatively weaker adsorbing fluids within a solid carbonaceous subterranean formation, and for recovering a gaseous eifiuent enriched in relatively weaker 3 5 adsorbing fluids from the formation.

WO 95127123 5 ~ ~ ~ PCl1US95103689 Another further object of the invention is to utilize the recovered gaseous effluent enriched in relatively weaker adsorbing fluids to enhance the recovery of methane from a solid carbonaceous subterranean formation.
Yet another further object ~of the invention is to provide a method for disposing of unwanted gaseous fluids within a solid carbonaceous subterranean formation that has been at least partially depleted of recoverable methane.
Still yet another further object of the invention is to provide a method for disposing of flue gas w'tthin a solid carbonaceous subterranean formation.
The above objects of the invention are satisfied by the following aspects of the invention:
The first aspect of the invemiion is a method for fractionating a mixture of gaseous fluids within a coal seam, lthe method comprising the steps of:
a) introducing a mixture of gaseous fluids comprising a 1 5 weaker adsorbing fluid component and a stronger adsorbing fluid component into the coal seam: and b) recovering a naffinate, enriched in the weaker adsorbing fluid component, from the coal seam.
In a second aspect of the irnrention, a method is disclosed for recovering methane from a solid carbonaceous subterranean formation penetrated by an injection well and a production well" the method comprising the steps of:
a) injecting a desorbing fluid having a volume peroentage of carbon dioxide equal to A into the solid carbonaceous subterranean formation through the injection well;
b) recovering an effluent comprising methane from the production well;
c) monitoring the composition of the effluent produced in step b); and d) ceasing recovery of the effluent produced in step bj when a 3 0 volume percentage of carbon dioxide in the effluent recovered in step b) is greater than 0.5 A.
In a third aspect of the invention is, a method is disclosed for recovering methane from a solid carbonaceous subterranean formation penetrated by an injection well and a production well, the method comprising the steps of:

R'O 95127123 6 PCT/US95/03689 21'~GS~~
a) injecting a desorbing fluid, having a volume ratio of carbon dioxide to other injected desorbing fluid components equal to B, into the solid carbonaceous subterranean formation through the injection well;
b) recovering an effluent comprising injected desorbing fluid and methane from the production well;
c) monitoring the volume ratio of the carbon dioxide to other injected desorbing fluid components contained in the effluent recovered at the production well; and d) ceasing recovery of the effluent from the production well 1 0 when the volume ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered at the production well is greater than 0.5 B and at least 70 percent of the methane available to the production well has been recovered.
In a fourth aspect of the invention, a method is disclosed for disposing carbon dioxide within a solid carbonaceous subterranean formation, the method comprising the steps of:
a) injecting a desorbing fluid, having a volume ratio of carbon dioxide to other injected desorbing fluid components equal to B, into the solid carbonaceous subterranean formation;
b) withdrawing a gaseous effluent having a volume ratio of carbon dioxide to other desorbing fluids of less than B from the formation;
and c) ceasing to withdraw the gaseous effluent from the formation when a volume ratio of carbon dioxide to other injected desorbing fluid components within the gaseous effluent withdrawn in step b) is greater than 0.5 B.
In a fifth aspect of the invention is a method for disposing of an unwanted gaseous fluid component within a solid carbonaceous subterranean formation, the method comprising the steps of:
a) introducing a gaseous fluid, comprising the unwanted gaseous fluid component, into the formation to sorb the unwanted gaseous fluid component to the formation; and b) maintaining disposal conditions within the formation to ensure that at least 10 peroent of a disposal saturation level of an unwanted gaseous fluid component remains sorbed to the formation.

In a sixth aspect of the invention, a method is disclosed for disposing of an unwanted gaseous fluid component within a coal seam, the method comprising the steps of:
a) introducing a gaseous fluid, containing the unwanted gaseous fluid component, inl;o the coal seam; and b) ceasing to introduce the gaseous fluid into the coal seam when the coal seam becomes saturated to a desired degree with the unwanted gaseous fluid cornponent.
In a seventh aspect of the invention, a method is disclosed for disposing 1 0 of an unwanted gaseous fluid component, the method comprising the step of:
injecting a gaseous fluid, comprising the unwanted gaseous fluid component, into a coal seam which is at least partially depleted of methane under disposal conditions to cause the unwanted gaseous fluid component to sorb to the coal seam and to minimize the release of unwanted fluid component to the atmosphere.
In some aspects, the invention provides a means for disposing of large quantities of an unwanted gaseous fluid within a solid carbonaceous subterranean formation. Some a;:pacts allow fluids such as flue gas, which may contain oxides of nitrogen, oxides of sulfur, carbon monoxide and/or carbon dioxide, to be introduced into a solid carbonaceous subterranean formation to enhance the recovery of methane from the formation. The invention further provides an efficient means for producing a nitrogen-enriched effluent stream which can be utiliza,i to enhance the recovery of methane from a solid carbonaceous subterranean formation. Other aspects allow fluids such as flue gas to be disposed of within a solid carbonaceous subterranean formation without requiring separate processing systems for the carbon dioxide and the oxides of sulfur.
Numerous other advantage:: and features of the present invention will become readily apparent from i:he following detailed description of the invention, the embodiments described therein, the claims, and the accompanying drawings.
BRI F D FiIPTION OF THE D AWIN =
FIG. 1 is a graph of the total gas production rate over time from a fully 3 5 methane-saturated coalbed into which several different gaseous compositions have been introduced.

R'O 95/27123 $ PGT/US95I03689 2 ~-~ ~ ~ g ~ FIG. 2 is a graph of the cumulative methane predicted to be recovered from the coaibed of FIG. 1.
FIG. 3 is a graph of the volume percent of methane predicted to be present in the effluents recovered from the coalbed of FlG. 1.
FIG. 4 is a graph of the volume peroent of nitrogen predicted to be present in the effluents recovered from the coalbed of FIG. 1.
FIG. 5 is a graph of the volume peroent of carbon dioxide predicted to be present in the effluents recovered from the coalbed of FIG. t.
FIG. 6 is a graph of predicted methane recovery rates for the coalbed of FIG.1.
FIG. 7 is a graph of cumulative methane recovered versus cumulative desorbing fluid injected into the coalbed of FIG. 1.
FIG. 8 is a graph of the cumulative volume of nitrogen recovered from a methane-depleted coalbed which is used to fractionate a mixture of gaseous fluids containing 15 volume percent carbon dioxide and 85 volume peroent nitrogen.
FIG. 9 is a graph of the cumulative mixture of gaseous fluids which are injected over time into the depleted coalbed of FIG. 8.
FIG. 10 is a graph of the recovery rate of nitrogen from the depleted coalbed of FIG. 8.
FIG. 11 is a graph of the total gas recovery rate over time from a fully methane-saturated coalbed. The graph compares the total gas recovery rate when pure carbon dioxide is injected into the bed to the recovery rate when a mixture containing 70 volume percent carbon dioxide and 30 volume peroent methane is injected into the coalbed.
FIG. 12 is a graph of the cumulative volume of methane predicted to be recovered from the cosibed of FIG. 11.
FIG. 13 is a graph of the volume percent of methane predicted to be present in the effluents recovered from the coalbed of FIG. 11.
FIG. 14 is a graph of the volume peroent of carbon dioxide predicted to be present in the effluents recovered from the coaibed of FIG. 11.
FIG. 15 is a graph of the predicted methane recovery rates for the coalbed of FIG. 11.
FIG. 16 is a graph of the predicted carbon dioxide recovery rates far the 3 5 coalbed of FIG. 11.

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F1G. 17 is a graph of the prei9icted total gas production rates for coalbed of FIG. 11.
FIG. 18 is a graph of predicted cumulative methane recovered from the coalbed versus cumulative desorbing fluid injected for the coaibed of FIG. 11.
DES(;RIPTION_OF THE EMBODIM NTS
While this invention is suscepltible of embodiment in many different forms, there is shown in the FIGS., and will herein be described in detail, specific embodiments of the invention. It should be understood, however, that the present disclosure is to be considered an exemplification of the prinaples of the invention and is not intended to lima the invention to the speafic embodiments illustrated.
Solid carbonaceous subterranean formations, such as coal seams, are comprised of carbonaceous material. The carbonaceous material includes a 1 5 matrix, having an extensive system of micropores, and a system of fractures which penetrate the matrix, commonly refereed to as "cleats". The system of micropores provides a large internal surface on which gaseous fluids can adsorb. The present invention exploits the differing adsorption strengths of various gaseous fluid molecules on the carbonaceous material of the formation, and the ability of large quantities of unwanted gaseous fluid components to sorb to the micropores of a carbonaceous matrix.
jpjs~ed ~a eo ~c FI sid In general, a gaseous fluid molecule that has a relatively stronger 2 5 adsorption strength will preferentially sorb to the carbonaceous material of the formation over a gaseous fluid molecule that has a weaker adsorption strength.
The amount of any gaseous fluid which will sorb to the carbonaceous material of a formation is dependent in part on the relative adsorption strength of the gaseous fluid for the carbonaceous matrix, the capacity of the carbonaceous 3 0 matrix for holding the gaseous fluid of interest, the tendency of the gaseous fluid molecules of interest to chemically ~~eact w'tth the carbonaceous material and thereby chemisorb to the material, and the pressure and temperature present within the formation.
An important factor in the operi~tion of the present invention is the relative 35 adsorption strengths of the components of an injected mixture of gaseous fluids 2 i~~~gg ~~/~123 to one another and to any fluids, such as methane, which may already be present w'tthin the formation.
For a carbonaceous material such as coal, it is believed that the atmospheric boiling point of a fluid is indicative of the relative adsorption strength of the molecules or compounds which make up the fluid. Table 1 lists the atmospheric boiling point of several common fluids.

Helium (He) -269C Weaker Adsorption Strength Hydrogen (H2) -253C

Nitrogen (N2) -196C

Carbon Monoxide (CO) -192C

Argon (Ar) -186C

Oxygen (02) -183C

Methane (CH4) -162C

Nitric Oxide (NO) -151 C _ .

Xenon (Xe) -108C

Ethane (C2Hg) -88C

Carbon Dioxide (C02) -78C

Suifur Hexafiuoride -64C

(SF6) Hydrogen Sulfide (H2S) -60C

Propane (C3Hg) -42C

Suifur Dioxide (S02) -10C

Nitrogen Dioxide (NOZ) 21C

Sulfur Trioxide (S03) 44C Stronger Adsorption suength ft is believed that, in general, the stronger adsorbing fluids have higher boiling points and the weaker adsorbing fluids have relatively lower boiling points. Therefore, the relative adsorption strength of one fluid component to another within a gaseous mixture and to other gaseous fluids within the formation can be determined by comparing their relative atmospheric boiling points. For example, carbon dioxide, with an atmospheric boiling point of i WO 95127123 _ _ _ P~~pS95I03689 -78°C, is relatively more strongly adsorbing to carbonaceous material than methane or nitrogen, which have atmospheric boiling points of -162°C
and -196°C respectively. The relative atmospheric boiling points of a fluid will provide one of ordinary skill in the art with general information relating to the relative adsorption strength of various gaseous fluids. However, the relative adsorption strength of various gaaeous fluids on a particular carbonaceous ' material of interest should be determined empirically where possible.
Further, the relative adsorption strength of various gaseous fluids will provide one of ordinary skill in the art with general information relating to the disposal of an unwanted gaseous fluid within a solid carbonaceous subterranean formation. However, the quantity of an unwanted gaseous fluid which can adsorb to a particular carbonaceous material should be determined empirically where possible. The empirical data will allow the quantity of gaseous fluid which can be disposed of within a solid carbonaceous 1 5 subterranean formation to be predicted more accurately. If chemisorptiom of a particular gaseous fluid component t~ the carbonaceous material of the formation is believed to be a significant factor, it also should be taken into account when determining the amount of unwanted gaseous fluid which can be disposed of within a formation.
The gaseous fluid may be introduced into the formation in either a gaseous or liquid state. A detailed description of suitable methods for injecting gaseous fluids in accordance with the invention may be found in the discussion relating to the injection of a nitrogen-enriched raffinate discussed below.
Other suitable ways of introducing gaseous fluids into a solid carbonaceous subterranean formation are known to one of ordinary skill in the art. If a gaseous fluid containing carbon dioxide is injected in a liquid state, it typically will change to a gaseous fluid within the formation. Aftematively, the gaseous fluid may be introduced into the fon~nation as a super-critical fluid.
Depending on the temperatures and pressures within the formation, the gaseous fluid may 3 0 either be maintained in the formation as a super-critical fluid or it may become a liquid, a gaseous fluid, or a co-existing liquid and vapor.
If the gaseous fluid utilized is near its critical temperature and pressure, it may be necessary to operate any production wells in a manner which will minimize the preapitation and/or ca~ndensation of solids and liquids within the 3 5 formation. A more detailed description of how to operate the production wells in such a situation is described below.

R'O 95127123 PCTlU59S103689 ~1'~~383 In this embodiment, a desorbing fluid containing a strongly adsorbing fluid is introduced into the solid carbonaceous subterranean formation through an injection well in fluid communication with the formation and an effluent containing methane is recovered from one or more production wells. The injection well preferably penetrates the formation.
The desorbing fluid typically is comprised of carbon dioxide and other fluid components, for. example nitrogen andlor methane. Because carbon dioxide is a strongly adsorbing fluid, it will preferentially adsorb to the carbonaceous material of the formation over other weaker adsorbing fluids such as nitrogen or methane.
During the conversion of organic matter to coal and other solid carbonaceous substances, methane is produced. The methane exists within 1 5 the formation both as free gas in the cleats and fractures of the formation and as sorbed gas within the carbonaceous matrix of the formation.
A carbon dioxide-containing desorbing fluid mobilizes both the free methane and the sorbed methane within the formation. The mobilization of the methane sorbed to the carbonaceous matrix occurs as a resuR of a lowering of the partial pressure of methane within the cleats and because carbon dioxide and other injected desorbing fluids competitively sorb to the carbonaceous matrix of the formation.
The partial pressure of methane within the cleats is lowered duo to the presence of injected desorbing fluid within the cleats near methane sorption sites. As the partial pressure of methane within the cleats is Powered, methane sorbed to the carbonaceous matrix will desorb from the matrix and diffuse to the cleats.
The competitive sorption of carbon dioxide and other injected desorbing fluids to the carbonaceous matrix will also cause methane to desorb from the carbonaceous matrix into the cleats. Once methane is within a cleat, the pressure gradient developed between the formation and a production well and/or weAs will move the methane to the production well or wells where it can be recovered.
Since methane is not as strongly adsorbed to a carbonaceous matrix as carbon dioxide, it will move faster through a solid carbonaceous subterranean formation than more strongly adsorbed gaseous fluids.

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The preferential sorption of stronger adsorbing fluids, such as carbon . ~ I
dioxide, within the carbonaceous matrix of the formation causes the injected desorbing fluid to be fractionated within the formation. The stronger adsorbing fluids will be preferentially sorbed to the region of the carbonaceous matrix surrounding the injection well into which the desorbing fluid is being introduced.
The stronger adsorbing fluids will continue to sorb to the matrix in the region . until the matrix is saturated with stronger adsorbing fluid. The relatively weaker adsorbing fluids will not sorb as strongly to the matrix and therefore will move faster through the formation than the stronger adsorbing fluids.
In general, as desorbing fluid is injected into the formation, the region within the formation which is saturated with stronger adsorbing fluid is being continually advanced forvvard toward a production well or wells. Therefore, it can be said that the stronger adsorbing fluids will forth what approximates a concentration front that advances within the formation. As desorbing fluid is 1 5 injected into the formation, the concentration front is Continually being swept from an injection well toward a region of lower pressure within the formation, ss.~~ as a production well.
Ahead of the front, the concentration of the stronger adsorbing fluids sorbed to the matrix is small relative td the concentration of stronger adsorbing fluids within the front or behind the front. Behind the front, the relative concentration of stronger adsorbing fluids, such as carbon dioxide, sorbed to the matrix approaches a steady-state value as desorbing fluid is continually injected into the formation through l:he injection well.
The steady-state value is dependent on several factors including: the relative adsorption strength of the stronger adsorbing fluids to the carbonaceous matrix as compared to the adsorption strength of the other fluids within the formation; and the relatiive concentration of the stronger adsorbing fluids contained within the injected desorbing fluid introduced into the formation.
Since the stronger adsorbing fluid components will be preferentially 3 0 sorbed by the formaflon, a desorE~ing fluid containing carbon dioxide can be injected into a solid carbonaceous subterranean formation while an effluent having a bwer carbon dioxide volume percent is recovered from a production well. The volume percentage of carbon dioxide within a mixture of gaseous fluids is sometimes hereafter referred to as a volume peroernage A.
3 5 Aiso, because the stronger adsorbing fluid components will move more slowly through the formation than llhe weaker adsorbing fluid components, an R'O 95/27123 PCT/US95103689 effluent, having a volume ratio of carbon dioxide to other injected desorbing fluid components which is less than the volume ratio of carbon dioxide to other injected fluid components within the desorbing fluid introduced into the formation, can be recovered from a production well. The volume ratio of carbon dioxide to other injected desorbing fluid components is sometimes referred to hereafter as a ratio B.
One type of carbon dioxide containing gaseous fluid which may be utilized in the invention is flue gas. Typically, the volume ratio B of carbon dioxide to other injected desorbing fluid components within flue gas is from 1 0 to 2I8. Another example of a cafion dioxide-containing gaseous fluid which may be utilized in the invention is a mixture of gaseous fluids which is rejected by a nitrogen rejection unit or a membrane separator which is separating carbon dioxide from a natural gas production stream. Typically, the rejected stream contains a volume ratio B of carbon dioxide to methane and other gases 1 5 of from 1/1 to 95/5.
It is believed the volume peroentage of carbon dioxide in the effluent recovered from a production well will be less than the volume peroentage of carbon dioxide in the injected desorbing fluid introduced into the formation until the region of the formation between an injection well and the production well 20 becomes saturated with stronger adsorbing fluid components. Additionally, it is believed the volume ratio of carbon dioxide to other injected desorbing fluid components contained in an effluent recovered from a production well will be less than the volume ratio of carbon dioxide to other injected desorbing fluid components within the desorbing fluid introduced into the formation, until the 25 region of the formation between an injection well and the production well becomes saturated with stronger adsorbing fluid components.
In an ideal situatiori, the solid carbonaceous subterranean formation is uniform, and a carbon dioxide concentration front will move radially outwardly from an injection well into the formation. However, there are very few solid 30 carbanacaous subterranean formations that show such uniformity. Most formations have regions through which the injected desorbing fluid will rapidly pass. These so-called "stringers" include regions of relatively higher permeability compared with the majority of the carbonaceous material.
Stringers also include regions that are comprised of materials to which the 35 desorbing fluid components do not readily adsorb. Examples of stringer regions that do not readily adsorb fluids include sandstone, carbonaceous 2~'~6~88 WO 95127123 --' PCT/US95/03659 shale, and other similar types of miateriais known to one of ordinary skill in the art, i The injected desorbing fiuici which passes through the stringers will at least partially bypass the carbonaceous material of the formation and is said to 5 "streak' within the formation toward a production well. The streaking will increase the relative amount of desorbing fluid present within an effluent recovered from a production well.
Additionally, injected desorbing fluid which travels through a stringer to a production wail does not contact as much of the carbonaceous matrix of the 10 formation as injected desorbing fluids which do not travel through stringers.
Therefore, injected desorbing fluid which travels through a stringer to a production well will not be as effectively fractionated into its respective components. Consequently, the volume ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered from the production 1 5 well will be increased above what vvoukl be expected in an idealized formation, but the ratio should still be reduced relative to the initial ratio B
contained in the injected desorbing fluid.
The preferential sorbtion of the stronger adsorbing fluid components within the formation, which causes the stronger adsorbing fluid components to move more slowly through the formation than the weaker adsorbing fluid components, allows stronger adsorbing fluids, such as carbon dioxide, to be disposed of within the formation. AAethods for disposing of carbon dioxide and other stronger adsorbing fluids within a solid carbonaceous subterranean formation acre discussed more fully below.
The ability of a solid carbonaceous subterranean formation to fractionate the injected desorbing fluid, with the majority of the carbon dioxide reaching the production well andlor wells at a later time than methane and/or other fluid having weaker adsorption strengths, provides a method for recovering a substantial portion of the methansr from a solid carbonaceous subterranean formation while simultaneously disposing of carbon dioxide within the formation.
As the method is carried out, the ratio of carbon dioxide to other injected desorbing fluids within the recovered effluent is preferably monitored at a ' production well or wells using methods known to one of ordinary skill in the art, such as a gas chromatography. This monitoring should provide a relative R'O 95/27123 ' 6 PCTIUS95103689 2~.'~6~$8 .
;.
indication of how the injected desorbing fluids are moving within the formation and whether the formation is becoming saturated with stronger adsorbing fluids.
As discussed earlier, the volume ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered at a production wail will be reduced relative to the volume ratio of carbon dioxide to other injected desorbing fluid components within the injected desorbing fluid introduced into the solid carbonaceous subterranean formation.
The ratio of carbon dioxide to other injected desorbing fluid components recavered.at a production well should rapidly increase once a carbon dioxide 1 0 front reaches the weilbore of a production well. See for example FIGS. 4, 5, 13, and 14. Also, the majority of the methane originally sorbed within the carbonaceous matrix located along the flow path of the injected desorbing fluid between an injection well and a production well will have been desorbed from the formation once the carbon dioxide concentration front has traveled from an 1 5 injection well to a production well (i.e. the carbonaceous matrix within the formation between an injection well and a production well along the flow path of the injected desorbing fluid will have been swept of the methane contained therein.) Also, as discussed earlier, actual solid carbonaceous subterranean 20 formations have stringers which can increase the volume percentage of the desorbing fluid contained within the effluent recovered from the formation.
Additionally, the amount of injected desorbing fluid required to sweep a formation can be increased due to the stringers.
Ono method which the inventors believe can effectively reduce the 25 amount of streaking which occurs within the formation utilizes the intermittent injection of a liquid such as water into an injection well. The injected water should selectively enter the higher permeability regions. Once the liquid enters the highor permeability regions it should reduce the flow of desorbing fluids through these regions. This will cause the injected desorbing fluid to be 3 0 redirected into regions of lower permeability, thereby increasing the vertical and area) swoop within the formation. By redirecting the injected desorbing fluids into regions of lower permeability, the time it takes for those fluids to travel from an injection well to a production well is increased. Also, because the redirected injected desorbing fluid may come into contact with more carbonaceous 35 material of the formation, the volume percentage of carbon dioxide within the effluent recovered from the production well and the volume ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered from a production well may be reduced.
Whether or not to cease recovery of effluent from a production well depends in part on the percentage of the available methane which has been recovered from the area of the formation drained by the production well. The available methane is that methane which is available for recovery from a production well. It should be noted that the methane available within the formation undergoing enhanced recovery may not be depleted, but the methane available for a specific production well may have been depleted. The quantity of methane contained in a solid carbonaceous subterranean formation can be determined by methods known to one of ordinary skill in the art. Examples of methods for calculating the quantity of methane within a formation are set forth in Yee et al. "Gas Sorption on Coal and Measurement of Gas Content", Chapter 9, pages 203-217, Hydrocarbon from Coal, published by the American Association of Petroleum Geologists (1993).
One of ordinary skill in the art who knows the quantity of methane contained in a formation and the composition of the injected desorbing fluid can calculate the available methane which can be recovered form the formation.
The decision of whether to continue to recover effluent from a production well also should take into consideration the value of the effluent. When determining the value of the effluent, it is important to take into consideration the processing costs required to further utilize the effluent stream. For example, if the effluent stream is to be sent to a natural gas pipeline the effluent stream may have to be processed to lower the percentage of inert gases contained therein to an acceptable level. The acceptable level for inert gases contained in natural gas is governed by natural gas pipeline specifications. If the value of the effluent is not great enough to justify further recovery of the effluent, then recovery of the effluent should be ceased or the method should be modified in an attempt to change the composition of the effluent stream to a point where further recovery is justified.
A methane containing solid carbonaceous subterranean formation under development may have several injection wells and several production wells. Due to the heterogeneity of most solid carbonaceous subterranean formations, a carbon dioxide concentration front from one injection well may reach a production well before the carbon dioxide concentration front from a second 2~'~6 ~~8 R'O 95/27123 PCTlUS95/03689 injection well reaches the same production well. This could cause the volume ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered from a production well to increase and approach or exceed the initial ratio B before the formation between the injection wells and a production well has been swept of available methane.
As can be seen from FIGS. 2, 3, 5-7, and 11-15, A substantial peroentage of the available methane may be recovered from a formation before the ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered from a production well reaches a value equal to the initial ratio B.
R is 1 0 believed that in some situation it is preferable to cease recovering effluent from the production welt when the ratio B is from 0.5 to 0.9 the value of the initial ratio B. For example, when the ratio of carbon dioxide to other injected desorbing fluid components within the recovered effluent is less than B, but a substantial percentage of the available methane has been recovered from the production 1 5 wail, ft may be preferable to cease recovery of effluent from the production well.
If the volume ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered from a production well is greater than the initial ratio B and a substantial percentage of the available methane has bean produced from that well, recovery from that production well preferably is 2 0 ceased.
If the volume ratio of carbon dioxide to other injected desorbing fluid components within the effluent recovered from a production well is greater than the initial ratio B, but there is a substantial percentage of methane still available to be produced from that production well, the recovery of effluent from that 25 production well is not preferably ceased. Instead, the flow of affluent from the production well should be restricted.
The restriction of flow from a production welt will increase the pressure within the well. This increase in pressure near the production well will cause the injected desorbing fluids to be redirected to areas of the formation with 30 relatively tower pressure. This restriction will improve the sweep of the formation end also reduce the streaking of injected desorbing fluid toward the production well from which flow has been restricted. Additionally, ft is believed that by increasing the pressure in the formation surrounding a production well, the preferential adsorption of carbon dioxide over methane to the carbonaceous 35 matrix will be enhanced. ft is believed this will reduce the volume percentage of carbon dioxide contained in the effluent recovered from the production well.

W0 95127123 ~ ~ ~ PGT/US95/03689 Several procedures may be utilized to restrict the flow of effluent from a production well. One procedure utilizes the introduction of a flow restricting material into the subterranean formation adjacent the. production well from which flow is desirably restricted. E;Kamples of materials useful for restricting the flow of effluent from a production well include, for example, carbon dioxide, acetone, pyridene diesel oil, polymers, epoxy, surtactant, foam, cement and mixtures thereof. The above listed materials reduce the flow of desorbing fluid within the formation by plugging or (binding the fracture system of the formation, thereby reducing the permeability of the affected area of the formation. In addition to the above listed materials, any material which causes the carbonaceous matrix to swell, theireby reducing its permeability, or plugs or binds the fracture system of the formation can be utilized.
Another method for restricting the flow of effluent from a production well involves operating a valve in fluid communication with the production well in such a manner that the flow of effluent from that production well is restricted. As with the earlier described techniques, the restriction of flow of effluent from the production well will increase the pressure within the well near the formation and provide the earlier discussed benefits which are believed to result from an increase in the pressure within the formation near a production well.
The above discussed procedures should assist in allowing the remaining methane available to the production well of interest to be recovered.
Any carbon dioxide which is recovered with the effluent is readily separable from the methane and ovther fluids present in the effluent, such as nitrogen. Examples of processes for separating carbon dioxide from an affluent stream include:
separation of carbon dioxide from a gaseous mixture using a membrane separator;
separation of carbon dioxide from a gaseous mixture using an adsorptive type separator, such as a pressure swing adsorptive separator; and cryogenic separation afi carbon dioxide from a gaseous mixture using a nitrogen rejection type unit.
The carbon dioxide containing stream which is produced by tho above processes also typically contains methane and/or nitrogen. If desired, the carbon dioxide-containing stream can be reinjected into the solid carbonaceous subterranean formation.

21'~G~8~

ft has been discovered by the inventors that it may be desirable in some instances to continue to recover effluent from a production well and reinject a substantial portion of the effluent stream back into the formation. Examples of situations where this may be advantageous are where there is a substantial 5 amount of available methane to be recovered from a production well, but the volume percentage of the carbon dioxide in the effluent stream is high. In this type of situation, the cost of separating the inert gases, such as carbon dioxide and nitrogen from the methane using conventional separation means, may be prohibitive.
10 In these situations, the inventors have discovered that it may be more advantageous to use the effluent stream to enhance the recovery of methane from another solid carbonaceous subterranean formation or a different region of the same solid carbonaceous subterranean formation. Preferably, the formation into which the effluent is injected is still capable of adsorbing a large quantity of 15 carbon dioxide.
The reinjected stream will be fractionated by the formation. The carbon dioxide contained in the reinjected stream will move slowly through the formation toward the production wells. As discussed earlier, the carbon dioxide will displace the methane from the formation. The methane contained in the 20 reinjeded stream shoukf travel faster through the formation toward a production well. It is believed the methane contained in the reinjected stream will also help in maintaining the reservoir pressure of the formation and therefore assist in recovering methane from the formation. FIGS. 11 through 18 graphically illustrate how in some circumstances a mixture of gaseous fluids containing methane and carbon dioxide advantageously can be used to recover methane from a solid carbonaceous subterranean formation.
pia_p~r_aai of Caseo~c Fluidc_ In this embodiment, a gaseous fluid which contains an unwanted 3 0 gaseous fluid component is introduced into a solid carbonaceous subterranean formation. The gaseous fluid is introduced into the formation through an injection well in fluid communication with the formation, preferably, through an injection well which penetrates the formation. The gaseous fluid is introduced into the formation at a pressure higher than the reservoir pressure of the 3 5 formation and may be introduced into the formation in either a gaseous or liquid state. Preferably, the gaseous fluid is introduced at a pressure below the j.. r_ 4~ ~~ .L t 21'6588 R'O 95127123 PGT/US95/03689 formation parting pressure of the fiortnation. If the injection pressure is too high and the formation fractures, the injected gaseous fluid may leak out of the solid carbonaceous subterranean formation into surrounding formations.
The gaseous fluid typically <;ontalns carbon dioxide and/or other gaseous fluid components which are n3latively more strongly-adsorbing to the carbonaceous material of the formation than methane. Examples of other gaseous fluid components which are typically contained in the introduced gaseous fluid include oxides of sulfur, oxides of n'ttrogen, and hydrogen sulfide.
These relatively more strongly-adsorbing gaseous fluids will preferentially sorb 1 0 to the carbonaceous material of the formation over any methane which may be present within the formation.
Flue gas is an example of a gaseous fluid which may be disposed of in accordance with the invention. Flue gas typically contains 10 to 25 percent carbon dioxide by volume, from about 75 to 90 percent by volume nitrogen, and small volume peroentages of oxides of nitrogen and oxides of sulfur. Another example of a gaseous fluid which may be utilized in the invention is the mixture of gaseous fluids which is rejectedl by a separation system which is separating carbon dioxide from a natural gas. production stream. Typically,.the rejected stream contains about 50 to 95 percent by volume carbon dioxide with the rest of the gaseous fluid being comprised mainly of methane. The rejected stream may also contain some hydrogen sulfide, oxides of nitrogen, and oxides of sulfur.
A solid carbonaceous subterranean formation utilized to dispose of unwanted gaseous fluid components, in accordance with this embodiment, preferably is depleted of recoverable methane, more preferably substantially depleted of recoverable methane, most preferably essentially depleted of recoverable methane. A formation which is depleted of recoverable methane is preferably utilized because the preferential sorption of fluids such as carbon dioxide to a solid carbonaceous subterranean formation will be enhanced within a formation which has an initially lower concentration of methane sorbed to its carbonaceous matrix. Also, if the pressure of the formation is reduced and the formation is depleted of recoverable methane, substantial quantities of gaseous fluids which are relatively weaker adsorbing than methane may be eff~cientiy disposed of within the fonmation.
In other situations, it may be preferable to utilize solid carbonaceous subterranean formations from which methane has never been produced. ft may 2~~~58~
W0 95127123 PCfIUS95103689 not be attractive to produce methane from such formations. Examples of such formations include formations with lour original methane in place and formations with low permeability.
A formation which is depleted of recoverable methane still contains some methane, but the methane is at such concentration that it is not economical to recover it from the formation. A formation which is depleted of recoverable methane has had at least 25 volume percent of the original methane in place removed from the formation. A formation which is substantially depleted of recoverable methane, has had at least 50 volume percent of the original methane in place removed from the formation. A formation which is essentially depleted of recoverable methane has had at least 70 volume peroent of the original methane in place removed from the formation.
One method for recovering methane from a formation utilizes pressure depletion of the formation. The reduction of pressure within the formation causes methane to desorb from the carbonaceous material and flow to a production well where it can be recovered. A coal seam which is produang methane through a production well using primary depletion will typically be abandoned when from 259'° to about 70°~ of the original methane in place has been recovered. The typical abandonment.pressures for such primary depletion wells range from 689,476 Pascais (Pa) to about 2,068,427 Pa.
Methane can also be recovered from coal seams using enhanced recovery techniques. An example of an enhanced recovery technique which can efficiently 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 which is using nitrogen enhanced recovery techniques, the percentage of methane recoverable from a seam is primarily dependent on the volume percentage of nitrogen contained in the production stream recovered from the formation. The production wells are typically abandoned once the percentage of nitrogen becomes too high and/or the percentage of methane becomes too low to justify further recovery. With current nitrogenlmethane separation technology, a production well will typically be abandoned when the volume percentage of methane in the effluent recovered from the formation is from 25~° to about 50%.
This corresponds to recovery of from 45~° to about 70% of the original methane in place w'tthin the formation. It should be noted that as more efficient methods are developed to separate methane from nitrogen, the amount of methane recoverable from a formation will increase. When a formation has used 2~'~6588 nitrogen to enhance the recover)r of methane from the formation, it may be preferable to reduce the pressure in the formation prior to disposing of an unwanted gaseous fluid component within the seam.
Another enhanced recovery technique which can effectively recovery methane from a solid carbonaceous subterranean formation is carbon dioxide enhanced recovery, which is more fully discussed above.
As discussed earlier, the stronger adsorbing fluids will be preferentially sorbed to the region of the carbonaceous matrix surrounding the injection well over relatively weaker adsorbing fluids. The stronger adsorbing fluids will continue io sorb to the matrix in the region until the matrix is saturated with stronger adsorbing fluid. Any relalJVely weaker adsorbing fluids, which may be presets within the formation, will not sorb as strongly to the matrix and therefore will migrate within the formation toward regions of lower pressure. In general, as gaseous fluid is injected into the formation, the region within the formation which is saturated with stronger adsorbing fluid is continually expanding away from the injection well.
Tho saturation level of any gaseous fluid component on the carbonaceous material of a formation is dependent on several factors including:
the relative adsorption strength of the stronger adsorbing fluids to the carbonaa~ous matrix as compared to the adsorption strength of the other fluids w'tthin the formation, the relative amcentration of the stronger adsorbing fluids contained within the injected gaseous fluid introduced into the formation, the capacity of a carbonaceous material for sorbing a particular gaseous fluid component, and the pressure and temperature prevalent within the formation.
For example, a typical San Juan Fruitland formation anal, which is totally depleted of methane, will sorb approximately 0.0246 standard cubic meters (SCM) of gas per kilogram of coal at 10,342,136 Pa and 46.1 °C, when the coal is allowed to reach saturation wiith a gaseous fluid containing 85 volume peroeM carbon dioxide and 15 volume peroent nitrogen. The sorbed phase on the coal will comprise approximately 99 volume percent carbon dioxide and approximately 1 volume pera3nt nitrogen. When the coal is allowed to reach saturation with a gaseous fluid cointaining 50 volume peroent a;rbon dioxide and 50 volume pera3nt nitrogen at the same temperature and pressure conditions, the coal will sorb approximately 0.0219 SCM of gas per kilogram of anal. The sorbed phase will comprise approximately 93 volume percent a~ubon dioxide and approximately 7 volume peroent nitrogen. For a gaseous fluid ..
containing 15 volume peroent carbon dioxide and 85 volume percent nitrogen at the same temperature and pressure, the coal will sorb approximately 0.0153 SCM of gas per kilogram of coal, the sorbed phase being comprised of approximately 70 volume peroent carbon dioxide and approximately 30 volume percent nitrogen. For a gaseous fluid containing 70 volume percent carbon dioxide and 30 volume percent methane at the same temperature and pressure, the coal will sorb approximately 0.0233 SCM of gas per kilogram of coal, with the sorbed phase comprising approximately S6 volume percent carbon dioxide and approximately 14 volume percent methane. The above calculated saturation levels are developed with the assumption that an unlimited quantity of gaseous fluid is available to the coal and that the weaker adsorbing gaseous fluid components are continually flowing by the sample and being replaced by fresh gaseous fluid so that additional stronger adsorbing gaseous fluid components can be preferentially sorbed to the coal. The enrichment of 1 5 strongly adsorbing fluid in the sorbed phase is a result of the preferential sorption which occurs within a solid carbonaceous subterranean formation. A
gal which is totally depleted of methane correlates to a coal seam which has less than approximately 10 volume percent of the original methane in place still remaining within the seam.
The above listed saturation levels for a particular unwanted gaseous fluid component are hereinafter referred to as 'disposal saturation levels.' The disposal. saturation levels for a particular unwanted gaseous fluid component are ratculated for a given temperature and pressure. The pressure and temperature, along with other operating parameters which are utilized to dispose of unwanted gaseous fluid components within the formation are referred to as disposal conditions. The disposal conditions are manipulated to maximize the quantity of unwanted gaseous fluid component which is sorbed to the formation. Typically, the disposal conditions are such that between 10 and 99 volume peroent of an introduced unwanted gaseous fluid component is disposed of within the formation. In some instances, ft is believed that greater than 99 volume percent of an unwanted gaseous fluid component can be disposed of within the formation. By disposing the unwanted gaseous fluid component within the formation, the unwanted gaseous fluid component's release to the atmosphere is prevented. Typically, maintaining disposal conditions requires only closing andlor controlling effluent paths from the formation to prevent the unwanted gaseous fluid component from being released from the formation while maintaining the pressure within the formation preferably below the parting pressure of the formation. In some instances, it may be advantageous to periodically dewater the formation to maintain or increase the formations capacity to sorb an unwanted gaseous fluid component. In some instances it may be advantageous to raise the 5 temperature prevalent within the formation. An example of a situation where it can be preferable to raise the temperature within the formation is where the unwanted gaseous fluid component chemically reacts with the formation and the reaction becomes more favorable as temperatures within the formation increase.
For a given solid carbonaceous subterranean formation, the disposal saturation levels 10 for a particular unwanted gaseous fluid component can be calculated by using an extended Langmuir adsorption isotherms model and the required empirical data for the given formation.
A description of an extended Langmuir adsorption isotherm model and how to utilize it to produce a model similar to the one used by the inventors' is disclosed in L.
E. Arri, et. al, "Modeling Coalbed Methane Production with Binary Gas Sorption," SPE 24363, pages 459-15 472, (1992) Published by the Society of Petroleum Engineers.
It is believed that the disposal saturation levels can be approached within a solid carbonaceous subterranean formation if there exists a method for removing the relatively weaker adsorbing fluid components from the formation so that more of the stronger adsorbing components can be introduced into the formation. The additional stronger adsorbing 20 components will continue to sorb to the formation until the disposal saturation levels are approached within the sorbed phase of the matrix. One way of removing the weaker adsorbing components from the formation would be to intermittently or continuously vent the weaker adsorbing fluids from the formation. Another way to remove the weaker adsorbing components from the formation would be to recover them through a production well. It is 25 believed that the formation can be saturated with unwanted gaseous fluid components to from 10 to 99 percent of the disposal saturation levels during the operation of the current invention;
preferably, from 50 to 95 percent; more preferably, from 70 to 90 percent.
In general, the pressure utilized by the invention is selected so as to optimize the sorption of the unwanted gaseous fluid component to the carbonaceous matrix of the formation. In general, the higher the pressure utilized, the more gas which can be sorbed by the carbonaceous matrix.

W0 95f27123 PC1YUS95103689 2~."~~a~8 .
As the gaseous fluid is introduced into a solid carbonaceous subterranean formation, the posttion of the unwanted gaseous fluid components within the formation, the relative concentration of unwanted gaseous fluid components within the formation, and the ratio of unwanted gaseous fluid components to other injected gaseous fluids are preferably monitored. One method of monitoring the formation involves obtaining samples of effluent from a monitor well. The samples are analyzed using methods known to one of ordinary skill in the art, such as gas chromatography. This monitoring will provide a relative indication of how the injected gaseous fluids are moving within the formation and the degree to which the formation is becoming saturated wfth the unwanted gaseous fluid component.
If the unwanted gaseous fluid component is a relatively stronger adsorbing fluid than the other injected gaseous fluid components, then the volume ratio of unwanted gaseous fluid component to other injected gaseous 1 5 fluid components within the effluent sampled at a monitor well will be reduced relative to the volume ratio of unwanted gaseous fluid component to other injected gaseous flu'~d components within the injected gaseous fluid introduced into the solid carbonaceous subterranean formation.
It believed that this reduction in the ratio of unwanted gaseous fluid components to other.injected gaseous fluid components is a result of the preferential sorption of stronger adsorbing fluid components, such as carbon dioxide, within the carbonaceous matrix of the formation. It is believed that the preferential sorption causes the relatively stronger adsorbing fluid components to move more slowly through the formation than weaker adsorbing fluid components. As discussed earlier, as gaseous fluid is introduced into the formation, the region within the formation which is saturated with stronger adsorbing fluid is being expanded away from the injection well. The stronger adsorbing fluid form what approximates a concentration front that advances within tho formation. As the gaseous fluid is introduced into the formation, the concentration front is continually being swept from the injection well toward a region of bwer pressure within the formation. The enrichment of the sampled effluent with other injected fluids will continue until the concentration front reaches a monitor well.
The ratio of the unwanted gaseous fluid component to other injected gaseous fluid components collected at a monitor well should rapidly increase once the concentration front reaches the region of the formation which the WO 95!27123 ~ ~ ~ ~ p~117S95103689 , monitor well drains. Due to the heterogeneity of most solid carbonaceous subterranean, the unwanted gaseous fluid component can move unevenly within the formation. This may cause the unwanted gaseous fluid component to become unevenly distributed within the formation. Therefore it is preferably to utilize more than one well to monitor the formation.
In one aspect of the invention, the introduction of gaseous fluid is continued until the formation is saturated to a desired degree with the unwanted gaseous fluid component. One of ordinary skill in the art will be able to determine the degree of saturation of a particular region within the formation by obtaining a gaseous effluent sample from a monitor well which penetrates the region of the formation.
The chemical composition of the obtained sample together with information relating to the pressure within the formation near the monitor well will enable one of ordinary skill in the art to determine the relative concentrations of each of the gaseous components sorbed within the carbonaceous matrix in the region of the formation from which the sample is obtained. This will allow one of ordinary skill in the art to determine if the unwanted gaseous fluid component of the injected gaseous fluid has reached the region from which the sample is obtained. It should also allow one of ordinary skill in the art to determine the degree to which the region of the formation is saturated with the unwanted gaseous fluid component. The desired degree of saturation within the formation is described more fully above in the description relating to disposal saturation levels.
As discussed earlier, if the unwanted gaseous fluid component is a relatively stronger adsorbing fluid, venting the formation will allow a larger quantity of unwanted gaseous fluid component to be sorbed to the formation for any given disposal pressure. The venting can take place through any well which is in fluid communication wish the formation. Venting, if utilized, may be pertormed continuously or interm'ttllentiy, and it may take place simultaneously 3 0 with injection of gaseous fluid or it may Occur after the injection of gaseous fluid has ceased.
If gaseous fluid components, such as hydrogen sulfide, oxides of sulfur, and oxides of nitrogen, are being disposed of, it may be preferable to reduce the pressure within the formation sufftcientiy to desorb carbon dioxide from ~~,:~
formation, but not enough to cause hydrogen sulfide, oxides of nitrogen, ~~~0 oxides of sulfur to desorb from the carbonaceous matrix. This venting of the W0 95127123 2$ PGTIUS95/03689 formation will allow a greater quantity of stronger adsorbing constituents, such as hydrogen sulfide and some oxides of nitrogen and sulfur, to be disposed of within the formation.
The injection of gaseous fluid into the formation can be intermittent or continuous. The injection of gaseous fluid is typically continued until the desired pressure is reacheii. After a desired quantity of gaseous fluid has been introduced into the formation or the formation has attained a desired pressure, the injection well is shut-in and the formation is preferably maintained at sufficient disposal conditions to maintain from 40 to 80 volume percent of the unwanted gaseous fluid components sorbed to the formation; preferably to maintain the unwanted gaseous fluid components sorbed to the fom~ation for at least one year after ceasing to introduce gaseous fluids into the solid carbonaceous subterranean formation.
Aftematively, the method of the invention is ceased after the formation 1 5 has bean saturated with the unwanted gaseous fluid to a desired degree. In carrying out the invention, it is preferable that less than 50 volume percent of the total quantity of unwanted gaseous fluid component introduced into the formation be allowed to escape to the atmosphere; more preferably less than 10 volume percent, most preferably less than one percent. The unwanted gaseous fluid components preferably are maintained within the formation for at least one year, more preferably at least five years, most preferably at least ten years.
Fra-ctionation of a Mixtere of Cac_eo~c Fluids In a further embodiment of the invention, a mixture of gaseous fluids containing relatively stronger adsorbing fluid components and relatively weaker adsorbing fluid components is introduced into a solid carbonaceous subterranean formation through an injection well in fluid communication with the formation. The relatively stronger adsorbing fluid components of the gaseous mixture will be preferentially adsorbed to the carbonaceous matrix of the formation. The current invention takes advantage of this preferential adsorption of the stronger adsorbing fluid components to the formation to provide a method for fractionating the mixture of gaseous fluids into a first fraction enriched in relatively weaker adsorbing fluids and a second fraction enriched in relatively stronger adsorbing fluids. Examples of mixtures of 3 5 gaseous fluids which may be fractionated include, but are not limited to:
air, flue gas, the gaseous mixtures produced from various industrial processes, and the - 2~7~588 i WO 95127123 PCTIUS95I03689 gaseous mixtures that are discharged from a separation unit which is separating nonflammable gases and condensible liquids from a natural gas production stream.
In this embodiment of the invention, the mixture of gaseous fluids typically is introduced into a solid carbonaceous subterranean formation through an injection well'which penetrates the formation. Preferably, the formation already has been deipleted of recoverable methane. Using a depleted formation should provide for better fractionation of the injected gaseous fluid. The pressure established on the formation will enhance the fractionation of the mixture of gassoous fluids into a fraction enriched.in stronger adsorbing fluids and a fraction enriched in relatively weaker adsorbing fluids. In general, the higher the pressure on the formation, the more gas which can adsorb to the carbonaceous matrix of the formation.
The fraction enriched in weaker adsorbing fluids (hereinaffer sometimes 1 5 referred to as the raffinatej is typii;ally withdrawn from the formation through a production well. The rafHnate will be enriched in relatively weaker adsorbing fluids because the relatively stronger adsorbing fluids which are preferentially adsorbed by the carbonaceous matrix will travel slower through the formation as described previously. -The raffinate is typically recovered from the formation until the concentration of stronger adsorbing fluids in the raffinate increases above an acceptable level. For a mixture of gaseous fluids containing carbon dioxide, the volume peroentage of carbon dioxide in the raffinate is preferably maintained less than 50 peroent, more preferably less than 20 percent, most preferably less than 5 percent. In some situations, it may be possible to maintain the volume percer>tage of carbon dioxide in the raffinate at less than 1 percent.
Alternatively, the injection a~f the mixture of gaseous fluids is continued until a desired saturation of the formation is achieved. The desired adsorptive saturation of the formation can be determined by routine experimentation. For example, the mixture of gaseous fluids can be injected until the volume ratio of the relatively stronger adsorbing fluids within the raffinate increases above an acceptable level as described above. Once the desired adsorptive saturation of the formation is reached, the carbonaceous matrix's adsorptive capaaty can be regenerated by reducing the total pressure on the formation. A desorbed adsorbate, which is enriched in relativeiy stronger adsorbing fluids, is released from the carbonaceous matrix of the formation as the total pressure of the W 0 95l 7123 PCTIUS95103689 2~'~~~8~ ao, formation is reduced. This desorbed adsorbate may be recovered from the formation through an injection and/or a production well.
If the mixture of gaseous fluids which is fractionated within the formation contains carbon dioxide, for example, flue gas, the desorbed adsorbate will be enriched in carbon dioxide. If the gaseous mixture contains oxygen, for example, air, the desorb~ed adsorbate will be enriched in oxygen. The recovered desorbed adsorbate can be reinjected into a solid carbonaceous subterranean formation. For example, if a mixture of gaseous fluids containing carbon dioxide is fractionated within a solid carbonaceous subterranean formation, the recovered desorbed adsorbate would be enriched in carbon dioxide. The recovered desorbed adsorbate enriched in carbon dioxide could be used to enhance the recovery of methane from a solid carbonaceous subterranean formation.
It may be desirable to maintain the relatively strongly adsorbing fluids 1 5 within the formation. In this situation, the pressure on the formation is not reduced and the adsorptive capacity of the carbonaceous matrix of the formation is not regenerated. Alternatively, the adsorptive capacity of the carbonaceous matrix of the formation can be partially regenerated without lowering the total pressure to the point where undesirable components such as carbon dioxide, hydrogen sulfide, or carbon monoxide, if present, may be desorbed and released from the matrix.
In general, the pressure utilized during the fractionation of the gaseous mixture of fluids is selected so as to optimize the fractionation of the fluid. In general, the higher the pressure utilized, the more gas which can be adsorbed by the carbonaceous matrix of the formation. For a given system, the faster the removal of raffinate from the system, the higher the volume percentage of the relatively strongly adsorbing fluids within the raffinate.
If the gaseous mixture of fluids to be fractionated contains a large volume peroentage of nitrogen, the resulting raffinate will be enriched in nitrogen.
Examples of gaseous mixtures of fluids which contain a large volume percentage of nitrogen include air and flue gas. The nitrogen-enriched raffinate produced from these gaseous mixtures of fluids can be utilized to enhance the recovery of methane from a solid carbonaceous subterranean formation. if flue gas is used, it should preferably be de-watered before it is injected into the formation. It is believed de-watering will reduce potential corrosion problems WO 95127123 ~ ~ ~ pCT/US95/03689 that can result in injection equipment and welibores as a result of injecting flue gas into a formation.
The nitrogen-enriched raffinate is injected into a solid carbonaceous subterranean formation at a pressure higher than the reservoir pressure of the formation. Preferably, the nitrogen-enriched raffinate is injected at a pressure of from about 3',447,378 Pascais (Pa) to about 10,342,136 Pa above the reservoir pressure of this formation. If the injection pressure is below or equal to the reservoir pressure, the nitrogen-enriched raffinate typically cannot be injected bec~iuse it cannot overoome the reservoir pressure. The nitrogen-enriched rafBnate is injected preferably at a pressure below the formation parting pressure of the solid carbonaceous subterranean formation. If the injection pressure is too high and the formation extensively fractures, injected nitrogen-enriched raffinate may be lost and less methane may be produced.
1 5 However, based on studies of other types of reservoirs, it is believed that nitrogen-enriched raffinate may be injected into the formation at pressures above the formation parting pressure as long as induced fractures do not extend from an injection well to a production well. In fact, injection above formation parting pressure may be required in order to achieve sufficient injection and/or recovery rates to make the process economical or, in other cases, may be desired to achieve improved financial results when it can be done without sacrificing overati performance. Preferably, the fracture half-length of the induced fractures witlhin the formation is less than from about 20% to about 30% of the spacing between an injection well and a production well. Also, preferably, the induced fractures should be maintained within the formation.
Parameters important to the recovery of methane. such as fracture half-length, fracture azimuth, and height growth, can be determined using formation modeling techniques which are known in the art. Examples of the techniques are discussed in Johni L. Gidley, et sl., Recent Advances in Hydraulic Fracturing, Volume 12, Scxiety of Petroleum Engineers Monograph Series, 1989, pp. 25-29 and pp. 76-77; and Schuster, C. L., "Detection Within the Welibore of Seismic Signals Creiated by Hydraulic Fracturing", paper SPE
7448 presented at the 1978 Society of Petroleum Engineers' Annual Technical Conference and Exhilbition, Houston, Texas, October 1-3.
Alternatively, the fracture half-lengith and impact of its orientation can be PCTlUS95103689 3z .
assessed using a combination of pressure transient analysis and reservoir flow modeling such as described in paper SPE 22893, 'Injection Above-Fracture-Parting Pressure Pilot, Valhal Feld, Norway; by N. Ali et al., 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 above reference describes'a method for enhanang oil recovery by injection of water above fracture-parting-pressure, it is believed that the methods and techniques discussed in SPE 22893 can be adapted to enhance the recovery of methane from a solid carbonaceous subterranean formation.
In general, the deeper the solid carbonaceous subterranean formation, the higher the pressure necessary to inject the nitrogen-enriched raffinate into the formation. Typically, an injection pressure of from about 2,757,903 to 13,789,514 Pa will be sufficient to inject nitrogen-enriched raffinate into a majority of the formations from which ft is desirable to recover methane.
The nitrogen-enriched raffinate is injected into the solid carbonaceous subterranean formation through an injection well in fluid communication with the formation. Preferably, the injection well penetrates the methane-containing formation, but the injection welt need not penetrate the formation as long as fluid communication exists between the formation and the injection well. The injection of nitrogen-enriched raffinate may be either continuous or discontinuous. The injection pressure may be maintained constant or varied.
A fluid comprising methane is recovered from a production well in fluid communication with the formation. As with the injection well, the production well preferably penetrates the 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 manner as conventional coalbed methane recovery wells. It may be desirable to minimize the backpressure on a production well during recovery of fluids comprising methane through that production well. The reduction of back pressure on the production well will assist the movement of the fluid, comprising methane, from the formation to the wellbore.
Preferably, a production well is operated so that the pressure in the production well at a wellbore location adjacent the methane-producing R'O 95127123 ~ g g PCT/OS95/03689 formation is less than the initial reservoir pressure of the formation. The wellbore location adjacent to the methane producing formation is within the welibore, not the formation. The initial reservoir pressure is the reservoir pressure near the production well ~of interest at a time before the initial injection of nitrogen-enriched raffinate into the formation. The reservoir pressure may increase during the injection of nitrogen-enriched raf~nate, but 'tt is believed that the pressure in the production wait near the formation preferably should be maintained less than the initial ireservoir pressure. This will enhance the rrwvement of fluid from the formation to the welibore. Most preferably, the pressure in a production well at a wellbore location adjacent the methane produang formation should be less than about 2,757,903 Pa.
In some instances, back-pressure on a production welts wellbore may be preferable, for example, when it is desirable to maintain a higher reservoir pressure to minimize the influx o11 water into the formation from surrounding aquifers. Such an influx of water into the formation could reduce the methane recovery rate and also complicate the operation of a production well.
Another situation where it csin be preferable to maintain back-pressure on a production well's welibore is 'when there is concern over the precipitation and/or condensation of solids and/or liquids within the formation near the weilbore or in the welibore itseH. The precip'ttation andlor condensatio°~ of solids or liquids in or near the welibore could reduce the methane recovery rate from a production well. Examplles of materials which may precipitate or condense out near the welibore sand present a problem are wax containing occluded oils which may be mobilized from the matrix and carried toward a production wellbore. tt is believed that a higher pressure in the production well's w~Ilbore at a location adjacent to the formation will minimize such precipitation and/or condensation of solids or liquids in or near the welibore.
Therefore, if precipitation and condensation in the wellbore are a problem, it may ba profarable to increase the pressure in the production well's wellbore to 3 0 a value as high as practicable.
The timing and magn'ttude of the increase in the rate of methane recovery from a production well will depend on many factors, including, for example, well spacing, thickness of the solid cs~rbona~ous subterranean formation, cleat porosity, injection pressure and injection rate, injected gaseous fluid 3 5 composition, sorbed gas composition, reservoir pressure, permeability of the R'0 95127123 PCTlITS95103689 2~.'~~~~8 formation, and cumulative production of methane prior to injection of nitrogen-enriched raffinate.
When the foregoing parameters are generally held constant, a smaller spacing between an injection well and a production well will result in a faster observable production well response (both an increase in the recovery rate of methane and a shorter time before injected nitrogen-enriched raffinate appears at a production well) than the response which occurs with an injection well and a production well separated by a larger spaang. When spacing the wells, the desirability of a fast increase in the rate of methane production must be balanced against other factors such as earlier nitrogen breakthrough when utilizing a reduced well spacing and the quantity of nitrogen-enriched raffinate utilized to desorb the methane from the formation for any given spaang.
if desired, methane produced in accordance with this invention can be separated from co-produced gases, such as nitrogen or mixtures of nitrogen 1 5 and any other gas or gases which may have been injected or produced from the solid carbonaceous subterranean formation. Such co-produced gases will, of course, include any gases that occur naturally in solid carbonaceous subterranean formations together with the methane. These gases which occur together naturally with the methane are commonly referred to as coalbed methane. These naturally-occurring gases can include, for example, hydrogen sulfide, carbon dioxide, ethane, propane, butane, and heavier hydrocarbons in lesser amounts. If desired, the methane produced in accordance with this invention can be blended with methane from other sources which contain relatively fewer impurities.
2 5 Examral9-1.
This example shows the predicted response of a coalbed when various desorbing fluids are injected into the coaibed to enhance the recovery of methane from the coalbed. In this Example injection is commenced at the one year point. All the desorbing fluids in this Example are injected into the coalbed at an injection pressure of 13,789,514 Pa. The desorbing fluids injected into the formation include:
pure nitrogen;
flue gas having 85 volume percent nitrogen and 15 volume percent carbon dioxide;
an equimotar mixture of carbon dioxide and nitrogen;

r a desorbing fluid having 85 volume percent carbon dioxide and 15 volume percent nitrogen; and pure carbon dioxide.
The data graphed in FIGS. 1-7 are generated from a model which was developed to S describe a hypothetical coalbed which is 3.05 meters thick and is homogeneous throughout in both the vertical and horizontal directions. The data graphed are corrected to a temperature of 15.6° and a pressure of 101,353 Pa. The hypothetical coalbed has the following characteristics:
permeability = 10 millidarcies;
10 porosity = 0.5%
reservoir pressure of 10,342,136 Pa prior to injection of desorbing fluid; and reservoir temperature = 46.1 °C.
The coalbed is saturated with methane and the area drained by the production well is a 186,155 square meter region of the formation. In the model, it was assumed that the 15 production well was surrounded by four injection wells which are arranged in a five-spot formation. It is assumed that each injection well affects the production well in the same manner and that therefore one quarter of the response in the production well is attributable to each injector. The cumulative desorbing fluid injected into the formation being drained by the production well comes from the four injection wells. Each injection well contributes 20 a quarter of the total desorbing fluid injected. FIGS. 1 through 7 show the predicted gas recovery rate (thousand standard cubic meters per day (MSCM/Day) and the predicted cumulative gas recovered (million standard cubic meters (MMSCM)).
The model utilized was developed using two-dimensional Virial equations of state.
A description of the Virial Equations of State and how to utilize them to produce a model 25 similar to the one used by the inventors' is disclosed in defiance, "Multicomponent high-pressure adsorption equilibrium on carbon substrates: theory and data," Fluid Phase Equilibria, 78, pages 99-137, (1992) Elsevier Science publishers B.V., Amsterdam.
As can be seen from FIGS. 1 and 5, the volume percentage of carbon dioxide in the fluid recovered from a production well is maintained at levels below the volume percentage 30 of carbon dioxide contained in the injected desorbing fluid for an extended period after injection of desorbing fluid is ~.~ ~ 127123 PCTlUS95f03689 commenced. The volume percentage of carbon dioxide in the recovered effluent starts to increase substantially at approximately the same time as the volume peroentage of methane in the recovered effluent starts to decrease. As can be seen from FIGS. 2 and 5, a substantial percentage of the available methane contained in the formation will have been recovered by the time the volume peroentage of carbon dioxide in the recovered effluent increases to above the volume percentage, of carbon dioxide in the injected desorbing fluid.
Also, since methods are available to economically separate carbon dioxide from methane, nitrogen, and other gases, carbon dioxide can be separated from 1 0 the effluent recovered from a production well and injected back into the coalbed andl or another nearby coalbed.
FIGS. 1,-7 also show that a substantial percentage of the available methane can be recovered from the region being drained by a production well before the volume ratio of carbon dioxide to other injected desorbing fluid 1 5 components contained in the effluent recovered from a production well reaches the magnitude of the volume ratio of carbon dioxide to other injected desorbing fluid components contained within the injected desorbing fluids.
It should be noted that since the model in the above example and the example that follows are idealized, they cannot take account of heterogeneities 20 present in an actual solid carbonaceous subterranean formation. Therefore, this model and the model described in Examples 2 and 3 do not predict the streaking which may oxur within the formation. However, the examples disclosed together with the earlier discussion regarding the. mitigation of streaking within a formation will enable one of ordinary skill in the art to practice 2 5 the invention.
Eusmgls32 This example shows the predicted response of a coalbed when desorbing fluids containing carbon dioxide are injected into the coalbed to enhance the recovery of methane from the coalbed. Injection of desorbing 3 0 fluids was commenced in this Example after four years of primary depletion. All the desorbing fluids in this Example are injected into the coalbed at an injection pressure of 13,789,514 Pa through injection wells having a skin of -3. The production well had a downhole production pressure of 689,476 Pa and a skin of -3. Skin is a measure of the permeability of the near wellbore formation. A
3 5 positive skin indicates near wellbore formation damage and a negative skin ., indicates near wellbore formation stimulation. The desorbing fluids injected into the formation include:
pure carbon dioxide; and a desorbing fluid having 70 volume percent carbon dioxide and 30 volume percent methane.
The data graphed in FIGS. 11-18 were generated from a model which was developed to describe a hypothetical coalbed which is 15.24 meters thick and is homogeneous throughout in both the vertical and horizontal directions. The data graphed are corrected to a temperature of 15.6°C and apressure of 101,353 Pa. The hypothetical coalbed has the following characteristics:
permeability = 5 millidarcies;
reservoir pressure of 10,342,136 Pa prior to injection of desorbing fluid; and reservoir temperature = 46.1 °C.
The coalbed is saturated with methane and the area drained by the production well is a 647,497 square meter region of the formation. In the model it is assumed that the production well is surrounded by four injection wells which are arranged in a five-spot formation. It is assumed that each injection well affects the production well in the same manner and that therefore one quarter of the response in the production well is attributable to each injector. The cumulative desorbing fluid injected into the formation being drained by the production well comes from the four injection wells. Each injection well contributes a quarter of the total desorbing fluid injected.
The model utilized was developed using the extended Langmuir adsorption isotherms model. A description of an extended Langmuir adsorption isotherm model and how to utilize it to produce a model similar to the one used by the inventors' is disclosed in L. E. Arri, et. al, "Modeling Coalbed Methane Production with Binary Gas Sorption, " SPE 24363, pages 459-472, ( 1992) Published by the Society of Petroleum Engineers.
This example illustrates that in some situations, which would be known to one of ordinary skill in the art from the foregoing disclosure, that a desorbing fluid comprising carbon dioxide and methane is preferably utilized to recover methane from a solid carbonaceous subteranean formation, especially if the cost of separating methane from a recovered effluent stream is not economically viable. In this situation, the effluent is reinjected into a formation which will C
2 ~-~ ~ '1~~ rb the carbon dioxide components, of the scream and allow the methane to pass to a production well where it is recovered.
This example uses the same type of modeling techniques and parameters as utilized in Example 2. However, in this example an unsaturated coalbed is utilized and a mixture of gaseous fluids having 15 volume peroent carbon dioxide and 85 volume peroent nitrogen is injected into the coalbed.
The injection of gaseous fluids was commenced at time zero. FIGS. 8-10 of the example show that a solid carbonaceous subterranean formation can effectively provide a nitrogen-enriched effluent when a mixture of gaseous fluids containing nitrogen and carbon dioxide is introduced into the formation. The model predicted that the volume percent of nitrogen in the recovered effluent would be 100% during the entire period graphed by FIGS. 8-10 that the volume percent of carbon dioxide in the effluent recovered would not increase to above 0.01 % during the entire period graphed by FIGS. 8-10.
It fs believed that a soled carbonaceous subterranean formation will also provide a nitrogen rich effluent when air is introduced into the formation through an injection well and removed through a production well.
From the foregoing description, it will _be observed that numerous variations, aftematives and modifications will be apparent to those skilled in the art. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the manner of carrying out the invention. Various changes may be made and materials may be substituted for those described in the application. For example, it is believed that a gaseous fluid which will chemisorb to the carbonaceous material of a formation may be disposed of in the formation in a similar method as disclosed for the disposal of a strongly adsorbing fluid within the formation.
Thus, it will be appreciated that various modifications, aftematives, variations, etc., may be made without departing from the spirit and scope of the invention as defined in the appended claims. It is, of course, intended that all such modifications are covered by the appended claims.

Claims

WE CLAIM:

1. A method for recovering methane from a solid carbonaceous subterran an formation penetrated by an injection well and a production well, the method comprising the steps of:
a) injecting a desorbing fluid, having a volume ratio of carbon dioxide to other injected desorbing fluid components equal to B, into the formation through the injection well;
b) withdrawing a gaseous effluent comprising methane and carbon dioxide and having a volume ratio of carbon dioxide to other injected desorbing fluid components of less than B from the formation through the production well; and c) ceasing to withdraw the gaseous effluent from the formation when a volume ratio of carbon dioxide to other injected desorbing fluid components within the gaseous effluent withdrawn in step b) is greater than 0.5 B.

2. The method of Claim 1, wherein the solid carbonaceous subterranean formation comprises at least one coal seam.

3. The method of Claim 1, wherein the injected desorbing fluid comprises flue gas.

4. The method of Claim 1, wherein the injected desorbing fluid contains greater than forty nine volume percent carbon dioxide.

5. The method of Claim 4, wherein the injected desorbing fluid comprises methane and carbon dioxide.

6. A method for fractionating a mixture of gaseous fluids within a coal seam, the method comprising the steps of:
a) introducing a mixture of gaseous fluids comprising a weaker adsorbing fluid component and a stronger adsorbing fluid component into the coal seam: and b) recovering a raffinate, enriched in the weaker adsorbing fluid component, from the coal seam.

7. The method of Claim 6, wherein a total pressure is established on the coal seam during step b) and the method further comprises:
c) lowering the total pressure on the coal seam to cause an adsorbate enriched in stronger adsorbing fluid component to desorb from the coal seam; and d) removing at least a portion of the desorbed adsorbate from the coal seam.

8. The method of Claim 6, further comprising:
c) injecting the raffinate into a second coal seam through an injection well; and d) recovering methane from the second coal seam.

9. The method of Claim 6, wherein the mixture of gaseous fluids introduced into the coal seam in step a) comprises flue gas and the raffinate recovered from the coal seam is enriched in nitrogen.

10. The method of Claim 6, wherein the raffinate recovered in step b) comprises methane.

11. The method of Claim 6, wherein the mixture of gaseous fluids introduced into the coal seam in step a) comprises methane and carbon dioxide.

12. A method for disposing of an unwanted gaseous fluid component within a solid carbonaceous subterranean formation, the method comprising the steps of:
a) introducing a gaseous fluid, comprising the unwanted gaseous fluid component, into the formation to sorb the unwanted gaseous fluid component, to the formation; and b) maintaining disposal conditions within the formation to ensure that at least 10 percent of a disposal saturation level of an unwanted gaseous fluid component remains sorbed to the formation.

13. The method of Claim 12, wherein from about 40 to about 80 volume percent of the unwanted gaseous fluid component sorbed to the formation remain sorbed to the formation after one year.

14. The method of Claim 12, wherein the solid carbonaceous subterranean formation is depleted of recoverable methane.

15. The method of Claim 14, wherein the unwanted gaseous fluid component comprises carbon dioxide.

16. The method of Claim 14, wherein the gaseous fluid introduced in step a) comprises flue gas and the unwanted gaseous fluid component sorbed to the formation is selected from the group consisting of oxides of nitrogen, oxides of sulfur, and mixtures thereof.