Title of Invention

METHODS OF EVALUATING UNDERSATURATED COALBED METHANE RESERVOIRS

Abstract The evaluation and assessment of geologic formations comprising undersaturated coalbed methane reservoirs. In some embodiments, the present invention provides for inductively quantifying critical desorption pressure of the solid in an undersaturated coalbed methane reservoir from an unrelated substance, the formation water. By using these techniques, the characterization of undersaturated coalbed methane reservoirs may be more quickly and economically made based upon a methane content characteristic such as critical desorption pressure, gas content, and in some embodiments gas content as calculated from isotherm evaluation, estimates of dewatering for production, and ratios of critical desorption pressure to initial reservoir pressure, among other possible characteristics. The features of the invention may further have applicability in combination with conventional reservoir analysis, such as coring, logging, reservoir isotherm evaluation, or other techniques.
Full Text METHODS OF EVALUATING UNDERSATURATED
COALBED METHANE RESERVOIRS
FIELD OF THE INVENTION
The present invention relates generally to the evaluation and assessment of
geologic formations comprising undersaturated coalbed methane reservoirs. Such
reservoirs usually have cleats and fractures initially saturated with water (i.e. no free gas
phase exists at reservoir conditions) and may represent gas-water systems. Specifically,
the present invention can provide methods of indirectly deducing important attributes
relative to methane that is sorbed in a solid formation substance such as coal from tests of
other than the coal itself. It permits a determination of critical desorption pressure of
methane contained in the solid formations of undersaturated coalbed methane reservoirs
and undersaturated conditions of the reservoir in general. In some embodiments,
economically significant characteristics can be determined such as estimates of
dewatering for production, methane content, among other aspects. The features of the
invention may further have applicability in combination with conventional reservoir
analysis, such as coring, logging, reservoir isotherm evaluation, or other techniques.
BACKGROUND OF THE INVENTION
Coalbed methane (CBM) is the composite of components that may be adsorbed on
coal at the naturally occurring conditions of reservoir pressure and temperature. As
pressure is reduced, the CBM begins desorbing from the coal once the critical desorption
pressure (CDP) is reached. CBM may consist largely of methane with smaller amounts
of impurities, typically nitrogen and carbon dioxide and some minor amounts of
intermediate hydrocarbons.
The capture and sale of CBM is a burgeoning industry both in the United States
and internationally. In the CBM industry, a typical procedure for CBM recovery is often
to penetrate the geologic formation with a substantially vertically drilled well and to
either 1) case the hole, typically with steel casing through the coal interval followed by
cementing the casing in place and perforating the interval all by methods commonly
known in the petroleum industry, or 2) to case in a like manner the hole to the top of the
coal and then drill through the coal, perhaps widening the hole drilled through the coal by
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a process known in the industry as underreaming. The former case is known as a cased
completion and the latter is known as an open-hole completion. In either case, when
producible water is present, typically water is pumped from the well through a tubing
string to the surface in an attempt to lower the reservoir pressure, a generally necessary
condition for releasing commercial quantities of CBM in most production scenarios. As
reservoir pressure is lowered, a free gas phase will eventually form at the bottom of the
hole and most of the free gas then will rise in the annulus between the casing and the
tubing by gravitational forces, allowing the relatively buoyant gas to be produced at the
surface from the annulus of the casing. The gas produced is then gathered and then
typically sent to markets through pipelines.
Many CBM wells that will ultimately produce commercial quantities of coalbed
methane do not do so when first put into production. The only gas produced initially in
such wells is the relatively minute, generally noncommercial, quantity of gas that is in
solution in the water at bottom-hole conditions of pressure and temperature. Most of this
minute quantity will come out of solution as the produced formation water moves from
conditions at the bottom of the hole to the lower pressure and typically different
temperature at the surface. Such coal formations that do not produce gas initially beyond
the amount contained in solution in the formation water are said to be undersaturated at
reservoir conditions of pressure and temperature. Other definitions for undersaturated
coals include: 1) when the storage capacity of the coal, typically expressed in standard
(usually 14.7 psia and 60 deg F) cubic feet of gas per ton of coal, exceeds the actual gas
content of the coal expressed in the same units at reservoir pressure, or 2) when no free
gas phase exists in the cleats and fracture system at reservoir conditions.
Storage capacity of the coal is typically determined in the laboratory from a
captured sample of coal. A plot of the data is often made having the ordinate typically
expressed in SCF/Ton and the abscissa being absolute pressure. This data is also often
statistically fit with an equation to yield a curve, one such commonly used curve being
known as the Langmuir isotherm as described in the reference of Yee et al., 1993. These
"isotherms", as the term implies, are measured at constant temperature generally
corresponding to that of the reservoir from which the sample was obtained.
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Unfortunately, some of the undersaturated CBM reservoirs may never produce
commercial quantities of coalbed methane. One concern, therefore, is the determination
of whether or not the coals in these undersaturated CBM reservoirs contain sufficient gas
to be commercial. Such information, if it could be determined expediently on a given
well in an exploratory area, could prevent the drilling of a large number of wells in the
specific area that may never produce economic quantities of CBM. As mentioned above,
one common method of making that determination is through the process of obtaining a
sample of the coal itself, perhaps by coring the coal, and subsequent detailed
measurement of gas content of that sample in a laboratory or otherwise. This technique is
typically expensive, and can require specialized drilling equipment and personnel.
Additional expense may be incurred when the core samples are sent to commercial or
private laboratories for analysis. The results of such core analyses are not immediately
available, sometimes taking months of desorption time. Also, because core analysis may
be too expensive for a large amount of sampling to be taken from a particular well,
samples, hoped to be representative, are often selected. Consequently, there is the
potential problem of the core samples not being representative of the formation even
nearby the well from which the core was cut; and there is an additional problem of how
representative the samples will be of the formation at some distance from the well. The
CBM industry is replete with examples of how gas content can drastically change over
relatively short distances. It is typically neither economically practical nor timely to have
every well cored and analyzed.
The results from a sample of the coal itself, perhaps from the coring process, can
also be very inconsistent from what is ultimately observed during production. During a
coring or other sampling operation, not only are samples of coal pulled for determining
gas content in the laboratory, but also a specific sample or a composite sample, possibly
made up from drill cuttings, may be gathered and this sample used to determine storage
capacity of the coal. This can involve tedious and expensive laboratory processes. The
commercial or private laboratory may then compare the gas content measured in some
samples with the storage capacity determined from another sample and estimate the
degree of saturation of the coal. As explained above, if the measured gas content is less
than the storage capacity, the coal is said to be undersaturated with gas, and the laboratory
will typically determine the pressure at which the gas content intersects a plot of the
storage capacity data. The resulting pressure is typically referred to as the critical
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desorption pressure (CDP). The CDP is the reservoir pressure at which CBM will start to
desorb from the coal with reduction of reservoir pressure, become a gaseous phase, and
begin to become capable of production in commercial quantities.
Unfortunately, the value of CDP determined by the laboratories, too frequently,
has been grossly in error from what was ultimately observed when the wells were
produced. The present inventor has identified such error in the coring and subsequent
laboratory analyses of several of approximately ten wells, analyzed under traditional core
analysis using different laboratories. Some analyses have indicated that the reservoirs are
saturated at reservoir pressure, yet these reservoirs have not produced any commercial
quantities of gas until the reservoir pressure has been drawn down to at least 50 to 60 %
of the initial reservoir pressure before reaching the CDP. Some of the analyses indicate
that the gas contents exceed the storage capacities of the coals at reservoir pressure,
something that appears to defy an adequate physical explanation.
In summary, coal sampling, coring, and subsequent core analyses as described
above may lead to results that are not only time consuming and expensive to obtain, but
also they can be highly questionable and frequently inconsistent when used for
individualized analysis. For individualized analysis, due to uncertainty, the better use for
coal sampling, coring, and core analyses may not come from individual assessments but
instead from multiple assessments from which composite isotherms are constructed for a
given geological region by averaging of the data and statistically demonstrating the
uncertainty. This has been done in the Powder River Basin (PRB) by the United States
Bureau of Land Management (BLM) as described in the reference to Crockett and Meyer,
2001. For example, from some 40 samples, the BLM has constructed an averaged
synthesized isotherm for samples measured in the PRB representing these 40 samples.
Even from such a relatively large number of samples, and ignoring the cost challenges to
achieve such data, this effort highlights the challenges in a coal sampling approach
because uncertainty in the data still exists. In fact this data shows significantly differing
isotherms that represent one standard deviation on either side of the mean curve.
Another problem under traditional analysis can, and does, occur in. some
undersaturated CBM reservoirs when one tries to demonstrate, perhaps through individual
testing or small-scale pilots of several adjacent wells, that the well(s) will ultimately
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produce commercial quantities of CBM. A long and uncertain dewatering period, even
under the best of circumstances, may be required before any commercial quantities of
CBM are produced. This can lead to long periods of evaluation time. In some areas
where there is high permeability and strong aquifer support, such as can be the case in the
PRB, one well cannot draw down the pressure sufficiently to ever reach the CDP in any
sort of practical or economic time frame. In response to this problem and in an effort to
evaluate their leases, most operators have drilled costly (multi-million dollar) multiple-
well pilots in an effort to cause interference between wells so that these wells, in
combination, can draw the pressure down sufficiently to reach the CDP by exceeding the
water influx into the pilot area. Some of these pilots have been successful in the PRB, but
some of the pilots have been dewatering for over three years without yet producing
commercial quantities of CBM. This dewatering is done at considerable cost of
equipment and power to pump wells, at a financial cost of deferred revenues and with the
uncertainty that the ultimate resource to be found may not be sufficient to be profitable.
The practical challenges of laboratory involvement and sampling difficulty known
to exist in a coal sampling-based technique are perhaps highlighted by reference to U.S.
Patent No. 5,785,131 to Gray. Although this reference involves techniques for sensing
formation fluids as in gas-oil systems when the fluid itself is of interest, as it relates to the
very different aspect of sampling solids containing a substance of interest, it proposes a
system for pressurized capture of the samples from entrained particles during drilling. In
the reference, these particles of coal or the like are captured and tested on site to avoid
some of the mentioned challenges of laboratory testing. As it relates to the solids such as
are of interest in the present invention, however, this reference still relies on a capture of
the entrained particles and as such it is subject to the uncertainties and other practical
limitations discussed above.
Another alternative to those techniques based on sampling of the coal itself
involves the use of mudlogging during drilling to obtain, at least a qualitative indication
of the presence of CBM. Some have even tried to quantify results (Donovan, 2001), but
these techniques can leave much to be desired and problems can exist because the system
is not usually closed, thus allowing unmeasured gas to escape. Gas-free drilling water is
also typically mixed with formation water of different gas content. Further, particle size
can need to be estimated, drilling speed recorded, etc. Then, too, results observed by the
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inventor for the PRB seem to indicate gas contents that are typically far in excess of those
observed. Finally, such techniques provide, at best, an estimate for gas content of the
coal and do not provide the practical accuracies desired, neither do these techniques
provide an estimate for CDP.
Other than the coal sampling-based techniques mentioned above, efforts (e.g., see
Koenig, 1988) have included attempts to determine CDP by producing the well and
dropping the pressure, perhaps by bailing or by a pump lowered into the well until gas
starts being produced. These techniques can be fraught with problems, some of which
are: 1) if a pump is used in the well, its capacity may not be sufficient to draw the well
down in a practical testing time frame to determine when gas starts being produced; 2) as
the liquid level drops in the well, air may be pulled into the casing from the surface, if the
casing is open at the surface, because the pressure in the casing will likely be lower than
the atmospheric pressure at the surface, or if the casing is isolated from atmospheric
pressure (e.g., shut in) a vacuum may be drawn on the well and a negative gauge pressure
(in this document gauge pressure will refer to measurement of pressure above
atmospheric pressure where zero gauge pressure would correspond to atmospheric
pressure) may result until there is sufficient release of gas from the coal to overcome the
vacuum being drawn by the falling liquid level; and 3) by the time the pressure is drawn
down sufficiently to see gas production at the surface, the reservoir may already be
affected by two-phase flow that may lead to complications in interpretation. This can
also produce results inconsistent with later production history.
SUMMARY OF THE INVENTION
Accordingly, broad objects of the invention may include providing techniques and
systems to evaluate undersaturated coalbed methane reservoirs and determine particular
characteristics of the coal in such reservoirs from other than a sample of the coal itself.
Further broad objects may include providing techniques and systems to determine critical
desorption pressure of coalbed methane reservoirs and other reservoir characteristics such
as characteristics that may be relevant to economic viability or the like. Each of the broad
objects of the present invention may be directed to one or more of the various and
previously described concerns.
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Further objects of the present invention may include the characterization and
evaluation of undersaturated coalbed methane reservoirs based upon characteristics such
as critical desorption pressure, gas content, gas content as calculated from isotherm
evaluation, estimates of dewatering for production, and ratios of critical desorption
pressure to initial reservoir pressure, among other possible characteristics as presently
disclosed.
Other objects of the present invention include characterization and evaluation of
coalbed methane reservoirs consistent with the techniques presently disclosed and
potentially in combination with conventional reservoir analysis, such as coring, logging,
reservoir isotherm evaluation, or other techniques. Naturally, further objects, goals, and
advantages of the invention are disclosed and clarified throughout this disclosure and in
the following written description.
To achieve the above-recited objects and the other objects, goals, and advantages
of the invention as provided throughout this present disclosure, the present invention may
comprise techniques and systems of testing a substance other than the coal or other solid
actually of interest in order to inductively quantify a methane content characteristic for
sorbed methane in the solid; to understand any factor that bears directly or indirectly on
methane content, including but not limited to bubble point, critical desorption pressure,
gas-water ratio, or the like. This invention even shows that a test of a characteristic of the
formation water, a substance whose characteristics may have been generally thought to be
unrelated to the amount of methane sorbed on the solid coal, can be used qualitatively and
quantitatively to determine gas content or the like of coal. In addition, the invention
shows that the test of the water can even permit inductive quantification of the critical
desorption pressure of the coal in an undersaturated coalbed methane reservoir. By
inductive quantification, it can be understood that the result is surprising, based on
previous knowledge of a person of ordinary skill in the art, in that it is a previously-
thought-of-as-being-unrelated-value that yields the desired result. From this method,
determinations can be deduced and inferred and the result can be obtained earlier and less
expensively than previously done. In some preferred embodiments, the invention
includes a method of determining critical desorption pressure of an undersaturated
coalbed methane reservoir comprising the steps of: determining a solution gas-water ratio
of formation water of the reservoir; determining the bubble point pressure of the
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formation water corresponding to the solution gas-water ratio; and determining critical
desorption pressure of the reservoir from the bubble point pressure of the formation
water. In other preferred embodiments, the invention includes a method of determining
critical desorption pressure of an undersaturated coalbed methane reservoir comprising
the steps of determining the bubble point pressure of the formation water of the reservoir
and determining critical desorption pressure of the reservoir from the bubble point
pressure of the formation water.
To further achieve the above-recited objects and the other objects, goals, and
advantages of the invention as provided throughout this present disclosure, the present
invention may comprise methods of undersaturated coalbed methane reservoir
characterization and characterizing the coalbed methane reservoir from characteristics
such as: critical desorption pressure, gas content, gas content as calculated from isotherm
evaluation, estimates of dewatering for production, and ratios of critical desorption
pressure to initial reservoir pressure, among other possible characteristics as presently
disclosed. The invention may also include determinations of critical desorption pressure
and characterization of undersaturated coalbed methane reservoirs in combination with
conventional reservoir analysis, such as coring, logging, reservoir isotherm evaluation, or
other techniques.
The present invention teaches that the bubble point of the formation water can be
used to inductively quantify the CDP of the coal in the coalbed methane reservoir and that
there is no requirement that the formation water remain in contact or carry with it coal as
may have been thought necessary. Thus, through embodiments, the CDP of coal in an
undersaturated coalbed methane reservoir may be quickly, easily, accurately, and
relatively inexpensively determined by the use of one or more CBM wells in an area, and
an excellent estimate of gas content can now be made. Further, as mentioned, an estimate
of the amount of dewatering necessary to reduce the reservoir pressure from its initial
value to the CDP can now be estimated in a practical manner.
Importantly, by knowing the CDP in a practical manner, ultimately an economic
analysis can now be made of the prospect a priori the drilling of a large number of pilot
wells, potentially at tremendous savings in time and investment costs to the operators.
Further, by the CDP being known in a practical and more economic manner such as
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disclosed as part of the present invention, it is now possible to use an isotherm to
determine gas content of the coal. Additionally, one can now more practically use an
isotherm specifically measured for an area, can use an isotherm determined in accordance
with techniques such as core analysis, may use correlations similar to the aforementioned
BLM correlations for a given geologic area, or even may (admittedly with less precision)
even use very general correlations based on rank of the coal such as are publicly known
(Eddy et al, 1982). Finally, through the present invention, one may not even have to use
an isotherm at all, but may be able to use the CDP to rank prospects for development in a
given geologic area where the variations in gas content may be due to varying degrees of
undersaturation.
The previously described embodiments of the present invention and other
disclosed embodiments are also disclosed in the following written description. The
entirety of the present disclosure teaches, among other aspects, a novel and nonobvious
method of characterizing, among other things, undersaturated coalbed methane reservoirs
of gas-water systems, and other techniques that circumvent many of the problems of
timeliness, inaccuracy and expense identified above for other state-of-the art methods.
BRIEF DESCRIPTION OF THE DRAWINGS
Figure 1 shows a relationship between solution gas-water ratio and bubble point
pressure such as might be determined in the laboratory at a given temperature and
salinity.
Figure 2 shows a statistical fit by cubic equation of measured data-representing the
solubility of pure methane in water (mole fraction of methane in the water-rich phase) at a
temperature of 100 degrees Fahrenheit with extrapolation to zero mole fraction at zero
pressure.
Figure 3 shows the extrapolation at pressures below 600 psia after conversion to
units of SCF/STB of the data of Figure 2.
Figure 4 shows a comparison of three prediction models for the solution gas-water
ratio at lower pressures: one based on a theoretical model, one using extrapolation of
9

public data, and one applying a linear extrapolation to publicly available salinity factored
data referred to as Hybrid.
Figure 5 shows approximate fits of the Langmuir equation with the statistical
uncertainty values for the isotherms determined by the BLM for the PRB.
Figure 6 is a set of publicly available curves that show the relationship between
maximum producible methane and depth of coal with rank of the coal as a parameter.
Figure 7 is an isotherm constructed in accordance with the present invention based
upon the above curve for subbituminous C coals.
Figure 8 (also referred to as Table 1) is a table of comparisons between gas
content determined from desorption of cores and various determinations of gas content
from the determination of CDP in accordance with the present invention.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
As summarized above, this invention involves new methods to evaluate a gas-
sorbed solid in a practical manner. Although initial applicability is envisioned for
methane such as may be contained in solids in commercial quantities such as an
undersaturated coalbed methane reservoir, it should be understood that it may be
expandable to other solids and other gases in appropriate circumstances. In initial
application it involves a situation where a well exists for a reservoir and sampling is
accomplished of a substance other than the solid itself from the reservoir. In a preferred
embodiment, the substance is the formation water present in the reservoir containing a
solid such as coal. This formation water is essentially uncoupled from any contact with
the coal and removed from the reservoir containing the solid and is tested in a relatively
easy manner to quickly yield information that permits an inductive quantification of some
characteristic of the solid in the reservoir. This characteristic may be a methane content
characteristic, that is information or data from which aspects relative to or influenced by
actual content data for the reservoir can be determined. From the inductively quantified
methane content characteristic, some characterization of the reservoir can be
accomplished. The invention can be embodied in several different ways and at least some
10

of those envisioned as the best ways to accomplish it are described below. Each feature
of the present invention is disclosed in more detail throughout this application, such as in
the following written description.
In one embodiment, the invention can involve a determination of a solution gas-
water ratio for the formation water of the reservoir. When a quantity of gaseous phase is
placed in contact with water and well mixed, all or a portion of that gas will go into
solution in the water. If all of the gas goes into solution leaving still a single phase of
water, the water is said to be undersaturated with respect to the gas. This means that the
water can still allow more gas to go into solution if the water were to be placed in contact
with an additional quantity of gas and well mixed. At some point, however, the water
will become saturated. In theory, the water is said to be saturated when addition of an
infinitesimal amount of gas well mixed with undersaturated water will cause the existence
of two phases in equilibrium, a gaseous phase and a liquid water phase. The amount of
gas that can be held in solution in water is a function of pressure and temperature of the
water, components of the gaseous phase, and the amount of impurities in the water (e.g.
salt concentration). The pressure at which the water becomes saturated with gas is called
the bubble point, so called because this is the unique pressure for a given temperature and
fluid composition where the first "bubble" of gas could exist as an independent phase
separate from the liquid water. As pressure increases, the amount of gas that can be held
in solution in the water increases. Over the range of temperatures typically encountered
in CBM reservoirs, the amount of gas that can be held in solution increases very slowly
with decreasing temperature. In the course of production of a CBM reservoir, in a
specific locality, the only one of these variables that is apt to exhibit major change in the
reservoir proper is pressure. However, once the fluids leave the conditions existing in the
reservoir, become uncoupled from the reservoir, and start making their way to the surface
by any means of conveyance that might be present and through the production facilities,
pressure and temperature also change. These changes in pressure and temperature impact
not only the amount of gas that can be contained in the water, but also the volume of free
gas (i.e. the gas that is not in solution) that may form on the way to the surface. For this
reason, it is convenient to represent the amount of solution gas present in a given volume
of water at reservoir conditions in terms of relative volumes at standard conditions. This
standard is typically atmospheric pressure at sea level (~14.7 psia) and 60 degrees
Fahrenheit. Thus, a common unit for solution gas-water ratio is SCF/STB (standard cubic
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feet of gas per stock tank barrel of water). There are a variety of ways to determine
solution gas-water ratio in accordance with the invention.
One method of determining solution gas-water ratio for the formation water is to
obtain a bottom-hole sample of undersaturated formation water and determine the
solution gas-water ratio and perhaps bubble-point in a laboratory. For the purposes of
this invention, a general objective of collecting a bottom-hole sample would be to obtain
a representative sample of formation water as a single liquid phase, but containing gas in
solution at or near the existing reservoir pressure and temperature. Standards have been
written for obtaining bottom-hole samples of undersaturated oil. The goal here is to
capture substantially pure formation fluid (that is fluid not tainted or contaminated by
drilling fluids or the like) and to assure that the formation water sample obtained is truly
representative of that existing naturally in the formation. The methodology employed and
described in detail in these standards is directly applicable to the procedure of obtaining a
bottom-hole sample of formation water, and thorough treatment and nuances of the
methodology can be found in the reference listed as that of American Petroleum Institute,
1966 that would encompass the following abbreviated description. Basically in obtaining
an appropriate sample, existing reservoir temperature and pressure may be measured and
recorded. In order for the sample to be representative of the formation water, the well
should be produced for a period long enough to remove all remnants of foreign fluids
introduced during the process of drilling and completion. The pressure should be lowered
at the bottom of the hole adjacent to the formation so that reservoir fluids will move from
the formation to the wellbore. During this production period, a small drawdown
(drawdown is the difference between the reservoir pressure and the bottom-hole
producing pressure) is recommended so that the pressure does not drop so low as to go
below the bubble point pressure of the formation water during sampling. If the bottom-
hole pressure drops below the bubble point pressure of the formation water, two phases
ma)' exist when the sample is taken at the bottom of the hole so that capturing the
appropriate amount of gas and formation water in the appropriate proportions can become ■
a significant problem. To obtain the sample, the well could continue to be produced at a
slow rate or it could be shut-in just prior to sampling depending upon the configuration of
the well and sampling equipment. A sampler described in the standards may be lowered
in the well to a level typically adjacent to the formation and a sample drawn. The sample
may then be remotely sealed to effect contained sampling at the bottom of the hole at or
. 12

above reservoir pressure, brought to the surface, and transported to the laboratory for
analysis commonly referred to in the petroleum industry as PVT (pressure-volume-
temperature) analysis.
If the well is being pumped or otherwise produced during the sampling of the
well, at least one representative sample could even be collected at the surface. This
sample could even be tested on site for the particular characteristic of interest. One
embodiment of the invention may comprise a fluid control such as a valve at the surface.
The valve may be closed during pumping until the pressure upstream of the valve exceeds
an estimate of the bubble point of the water, and consequently the CDP of the coal. A
reasonable guideline would be to adjust the valve until the pressure upstream of the valve,
is at or above the static bottomhole pressure, perhaps after a few days of shut-in prior to
obtaining the sample. Placing the pressure ahead of the valve above the static bottomhole
pressure could help to assure representative samples, such as to assure that the typically
small effect of temperature change from bottomhole conditions to surface conditions
would not change the phase relationship from single-to two-phase ahead of the sampler.
In this manner, the sample collected upstream of the valve and at the pressure ahead of
the valve, may be more representative as single-phase when captured. Samples could
then be sent to a laboratory for analysis, potentially after having been adjusted to
reservoir temperature. Also, whether or not taking the temperature effect into account
and/or other such effects, one could make an approximation of bubble point pressure
and/or solution gas-water ratio on site by reducing the pressure on the sample and
observing the relative volumes of gas and water at atmospheric pressure such as through a
sight glass or by other indicator if the sampler is so equipped. Further on-site expedients
to obtain an estimate of the bubble point of the water could include: 1) acoustic detection
of two-phase flow by lowering the pressure upstream of the valve until an audible
difference is noted between single-phase and two-phase flow with the corresponding
value of upstream pressure being an approximation for the bubble point, and 2) by noting
the contrast in frictional head loss in going from single- to two-phase flow such as could
be accomplished, for example, by measuring the differential pressure drop in a section of
the pipe upstream of the valve.
If accomplished at a laboratory, a suite of measurements can be made on the
sample of undersaturated formation water. Regardless as to where made, testing can
13

include determination of solution gas-water ratio perhaps either by making a single
determination by dropping the pressure to some prescribed low pressure, perhaps at
approximately zero absolute pressure, and measuring the amount of gas released in the
process and dividing this by the volume of water in the sample. In addition, one can test
for the solution gas-water ratio at only a prescribed number of pressures so that a solution
gas-oil ratio versus absolute pressure curve can be constructed. This option may be
preferable because of its broad application as described below with regard to bubble point
determination features.
In determining the solution gas-water ratio, it is possible to utilize or determine a
variety of gas and other factors, including but not limited to the composition of the
released or obtained gas (methane, carbon dioxide, etc.), the surface temperature, the
surface pressure, the gas remaining dissolved after the test, and to factor these aspects into
the test results. It is also possible to utilize or determine the composition of the formation
water and to factor these aspects as well into the test. Of importance in this regard can be
the effect of salt concentration.
It is recommended in some embodiments that the full suite of tests, if made at all,
be made only on one or a few wells in a new area of development. The solution gas-
water ratio as a function of absolute pressure obtained in the process could then be used to
determine the bubble point pressure of the formation water and the CDP of the reservoir
as taught here. Some or all of the data conducted on the samples given the full suite of
tests can then be applied to other samples and other wells in the new area and this may
yield results that are more accurate than the use of general, theoretical or published
correlations.
Another method that can be used to determine the solution gas-water ratio of the
formation water by measurement of produced quantities of gas and water: Although this
method may produce results slightly less accurate than results from bottom-hole
sampling, when the time and expense of obtaining and analyzing bottom-hole samples is
taken into consideration, direct measurement may be the preferred way to determine
solution gas-water ratio. As in bottom-hole sampling, it may be desirable that the
formation water be a single phase at bottom-hole conditions with the only gas present at
bottom-hole conditions adjacent to the formation being that which is in solution in the
14

formation water. Indeed, if it is not single-phase at conditions existing in the coal, then
the reservoir is likely saturated and the invention described here may be neither necessary
nor applicable. It may not be necessary because if it is known that the coal is saturated,
one only need record the existing reservoir pressure (e.g. perhaps by equating the bottom-
hole pressure, after sufficient shut-in, to the reservoir pressure). The reservoir pressure
(i.e. when two phases exist) would correspond to the current desorption pressure and this
fact would be recognized by most skilled in the art.
When the formation water is undersaturated ~ as of interest in the present
invention — the reservoir pressure is higher than the bubble point pressure of the
formation water. In such a situation, the solution-gas/formation water ratio can be
directly measured or tested in accordance with the present invention by testing produced
quantities of gas and water. In this embodiment, it is usually desirable to keep the
bottom-hole pressure higher than the bubble point. This can be done by producing the
well at very small drawdown (the difference between reservoir pressure and bottom-hole
producing pressure) so that the bottom-hole producing pressure is kept above the bubble
point pressure. Since one does not know a priori the bubble point pressure (indeed that is
what is being sought), it can be practical to assume that the bubble point pressure is below
the producing bottom-hole pressure and then verify that assumption during the
measurement and subsequent estimation of bubble point pressure. After a well is
completed, is in communication with the coal formation, and is shut in for a sufficient
period to allow the bottom-hole pressure to become the same as the reservoir pressure,
one can then measure the pressure of the fluids immediately in contact with the wellhead
at the surface. If there is negative gauge pressure (psig) present at the surface, the well is
actually drawing a vacuum. This can be caused by: 1) some reduction in reservoir
pressure (perhaps by production of nearby wells), or 2) by the bottom-hole pressure being
higher than the reservoir pressure (perhaps achieved while drilling) when the well was
shut-in before the bottom-hole pressure had a chance to fall off to the reservoir pressure.
Regardless of the cause and to use this production method, such a well will have to be
produced by artificial means such as by a downhole pump. Such a condition can be taken
as strong evidence that the fluid at the bottom of the hole is a single water phase and if
fluids there are representative of the formation, therefore, strong evidence that the coal is
undersaturated. If the gauge pressure of the fluids in contact with the surface of the shut-
in well is zero and if there is communication between the well and the formation, this
15

again may be taken as an indication not only that that the well will most likely have to be
produced by artificial means to conduct the test, but that the coal is undersaturated, and
that the bottom-hole pressure was equal to formation pressure at shut-in. If the gauge
pressure at the surface of the shut-in well is positive, then it may be important to know
what fluid is at the surface of the well. This can be accomplished by opening a valve at
the surface. When the valve is opened, if the well continues to flow gas, even at a small
rate for a long period (perhaps several hours to several days), this may be taken as a good
indication that the well is two-phase at bottom-hole conditions and, as explained above,
the coal is probably saturated and the shut-in bottom-hole pressure will be at or near the
current desorption pressure of the coal. If the well quickly (perhaps less than 15 minutes)
quits producing any gas and is not followed by any water production when the valve is
opened, then the pressure on the casing could have been caused by some other
phenomenon (e.g. the well may have been producing water and the well shut in at the
surface before the bottom-hole pressure had a chance to build up to the reservoir
pressure). Such a well may have to be produced by artificial means in order to conduct
the test. If the well begins to flow or immediately flows only water or mostly water when
the valve is opened, then the well will likely flow on its own without artificial means and
is called a "flowing" well.
More than likely when the casing pressure is accompanied by water at the surface
with little or no gas preceding it, the reservoir is undersaturated and the well can be tested
and the solution-gas ratio determined directly just by opening the valve and by producing
it through separation facilities that will allow the calculation of producing gas-water ratio.
On the way to the surface, the pressure in such a situation drops in the fluid from its high
at bottom-hole conditions, to its low at the surface at atmospheric pressure. When the
transported fluid reaches its bubble point on the way to the surface, gas breaks out of
solution and forms an independent phase. More and more gas comes out of solution as
the transported fluid reaches lower and lower pressures on its way to the surface. One
embodiment of the present invention makes use of the fact that eventually, but usually
within minutes, a stable rate can be achieved perhaps with the aid of a choke valve
installed at the surface and altering the setting on that valve to alter the production rate.
At the surface, the mixture of water and gas may be routed through separation facilities,
so that the producing gas-water ratio (i.e., the ratio of produced gas at standard conditions
to the volume of water produced) can be directly determined. In such a situation it may
16

be desirable that there be a constant fluid production, that is that the water production rate
be held relatively constant during several determinations of the producing gas-water ratio
over the course of several hours or perhaps as long as a day. Initial sampling can occur,
followed by additional production, and then additional sampling, with comparison of test
results or comparing samples. In applying the invention taught here on newly drilled
wells, the inventor has found that a good system is to start production on one morning,
make a measurement at the end of the workday and come back the next morning or at
least longer than a traditional formation water re-sampling time and make another
measurement using similar tests to determine accuracy. In this manner, comparing the
results of the multiple similar tests can yield an accuracy determination. If the preceding
day's producing gas-water ratio is essentially (within the uncertainty of the measurement
employed) the same as the one obtained the next morning then the conditions in the
formation adjacent to the bottom of the well are single-phase and the value of producing
gas-water ratio is approximately equal to solution gas-water ratio of the formation water.
In many cases, the determination can be made over the course of several hours, but the
inventor has seen at least one case where the measurement did not become constant until
the following day. In existing producers that have been under production for some time
but are not yet producing commercial quantities of CBM, the results can be obtained very
rapidly because presumably all remnants of foreign fluids introduced during drilling
would be gone. Of course, the latest measurement should be most representative of the
formation water as long as the bottom hole pressure remained above the bubble-point
pressure during the course of the test. Any sort of trend in the data with time may be
considered troublesome. If there is any sort of trend in the data with time or production
rate, either increasing or decreasing with increasing rate, thgn the bottom-hole producing
pressure may have dropped below the bubble-point pressure of the formation water
during the test period and the value of producing gas-water ratio may not be fully
representative of the solution gas-water ratio. Also, in severe cases of invasion of drilling
fluid or stimulation fluid into the formation, the measurement may not be representative
of the formation water. If such concerns exist, the production test could be extended over
several days until it is possible to achieve a constancy or at least substantially constant
producing gas-water ratio or other parameter (e.g., bubble point, CDP, etc) so that the
sampling yields a constant result whatever it may be. This inventor has gone back after a
week or two of production on several occasions and determined that the same producing
gas-water ratio existed as before. One could also utilize on site a chromatograph to
17

analyze the gas coming out of the water during the test to assure that the components
measured are consistent with known compositions of CBM in the area. Such consistency
would suggest that the test had been run long enough. High values of nitrogen might, for
example, suggest that the gas in the water is contaminated by air introduced during
drilling or underreaming and a longer period of production might be required to get water
entering the pump that is representative of the formation water.
As implied from the earlier discussion, when the gauge pressure of the fluids at
the surface is either negative or zero, the well will not flow on its own volition and some
type of production equipment may be required to perform the test. Production equipment
can vary tremendously regarding the types of pumps and well configurations for those
pumps, but in this document, only one example will be given as the various pumps and
pump configurations are generally known in the industry. This should not be viewed as
limiting, however. In many geological basins including the Powder River Basin, a
submersible pump is lowered on the end of production tubing to the approximate depth of
the coal formation. In some applications, no packer is used to isolate the producing zone
from the annular volume in the well above the packer. When there is no packer,
frequently the wellbore, either as created by the original drilling process or enlarged by
other means, is used as a bottom-hole separator where it is intended that, once gas begins
to flow as an independent phase, most of the gas will be forced by buoyancy up the
annulus between the tubing and casing, allowing water and a typically insignificant
amount of gas to flow up the tubing. The gas that flows up the annulus is often gathered
at the surface and sold. The small amount of gas that comes from the tubing is, however,
typically vented and not captured. This configuration can be used to determine the
producing gas-water ratio and ultimately the solution gas-water ratio. For the purposes of
this determination, it may be beneficial to locate the pump close to the formation on the
end of a tubing string for two reasons: 1) A lesser amount of water needs to be removed
to start retrieving fluids representative of the formation water than if the pump was
located farther up the hole, and 2) more importantly, the pressure can be maintained high
enough to exceed the bubble-point pressure of the formation water before entering the
pump. In accordance with one embodiment, the pump may be turned on at a practical,
but relatively slow rate with limited drawdown in an effort to keep the bottom-hole
pressure above the bubble point pressure at the bottom of the hole during the course of the
test. The water production rate may then be stabilized. When the water production rate
18

no longer requires frequent adjustment, then the measurements may begin. Alternatively
and preferably, a pressure transducer can be installed above the pump so that the fluid
level can be observed during the test. In this embodiment, when the fluid level does not
change significantly, then the measurements may begin. With the fluid level relatively
constant in the well, fluids entering the pump will be largely those coming from the
formation and not fluids that might not be representative of the formation that could be
pulled into the pump from the annular volume between the tubing and the casing above
the formation. Alternatively, a packer could be set to isolate the fluids in the annulus
above the pump from the fluids below the pump. The water then enters the tubing at the
bottom of the hole as a single water phase. At this point the test proceeds in essentially
the same manner as that described at above for a flowing well, with the same attempts to
make the direct measurement indeed be one of a sample that is representative of the
virgin formation water. As in the case of a flowing well, the produced fluids or a portion
of the produced fluids are taken to separation facilities where an accurate determination
of producing gas-water ratio can be made. Several measurements of producing gas-water
ratio can be made; and in some embodiments should be made over the course of hours, a
day, or even a week as discussed above for the flowing well case. As before, if any sort
of trend is evident in the data with time or rate, or if the producing gas-water ratio does
not approach some constant value, there is a chance that the measured producing gas-
water ratio will not be representative of the solution gas-water ratio of the formation
water and consequently, the value of CDP ultimately obtained may not be accurate.
Sometimes the well will be so severely damaged or the permeability of the
formation so low that the pump cannot operate at such a low rate to keep the fluid level
constant. An option in accordance with an embodiment of the present invention may be
to pump off the well, in essence permitting an inappropriately low pressure and producing
substantially all of an initial well volume, and then allow the well to rebuild pressure, to
refill over the required time (perhaps several days) to at or near its original fluid level.
The well can then be produced, and once one well or well pathway volume above the
pump has been produced in some embodiments, sampling may commence. It may be
preferable to sample before the fluid level drops too low to be representative. These first
sampled fluids, collected after the displacement of one tubing volume, are more likely to
be representative of the formation fluid under adverse situations such as a tight reservoir
and/or severe well damage. Conducting the test in this manner cannot be expected to
19

yield results as what could be achieved with a longer test, but it may allow salvaging a
test that might otherwise be aborted.
Other methods of determining solution gas-water ratio may also be used in various
other embodiments of the present invention. Any method of determining the solution
gas-water ratio would be consistent with the features taught of the present invention and
is a relevant step in combination with other features and in application of the invention.
These may range from low-tech systems and techniques to more advanced methods
perhaps even including the separation and pressure measurement methods of the Gray
patent reference where one releases a limited amount of pressure and observes a pressure
buildup. For example, it is also possible that a representative sample of formation water
could be obtained through the drill stem in a procedure that would fall under the general
category of drill stem testing as discussed by the Earlougher reference, 1977. Drill stem
testing is a way of temporarily completing a well during the process of drilling so that
evaluations of the formation and formation fluids can be made without the expense of
completing and casing a well. In drill stem testing, a tool is often lowered into the hole at
the end of the drill pipe, the zone of interest is isolated by formation packers and the drill
pipe is used to transport fluids from the formation to the drill stem and these fluids can be
sampled and analyzed for fluid properties. With the caveat that precautions should be
taken to assure that any sample of formation water is truly representative samples
obtained through the drill stem sampling technique can be used in embodiments of the
present invention. If adequate pressure exists, then the well could be flowed at the
surface, and determining the solution gas-water ratio could be determined as described
above for the case where a positive fluid pressure exists at the surface. Optionally, a
pump could be run in on the drill string or on tubing by the drlling rig and a test could be
conducted in a manner similar to the techniques described here. This would have the
advantage of obtaining immediate results, but the disadvantage of having to pay rig time
while the test was being conducted.
As another technique, at least one company, Welldog, Inc., is aspiring to come up
with means of determining the gas content of the coal formation by a tool for which a
patent application has been filed. While this tool is designed to specifically determine the
CBM content of coals, presumably it, or a similar device based on the same concept,
20

might also be used to obtain and test formation water and to then achieve the present
invention.
As yet another example, it might also be possible to locate the pump higher up in
the hole, at a location remote from the reservoir, instead of adjacent to the formation in
the situation where a pump is installed to test the well as described above. This situation
might result in an accurate assessment depending upon how low the bubble point of the
formation water actually was. If gas begins to come out of solution below the pump,
however, the results could be very hard to interpret as part of the gas could go up the
annulus and part would go through the pump. The gases from both the production tubing
and the tubing-casing annulus could also be combined at the surface to effect a contained
sampling of both the formation water and the gas, essentially the total gas content of the
water. Solubilized and desolubilized methane can be captured to effect an accurate
determination. These two can then be measured through separation equipment. As long
as the bottom-hole pressure at the well bottom remains above or at least at the bubble
point of the formation water, and no phase separation is permitted at this location, this
recombination of gases and measuring of the production rate of the recombined amount
divided by the production rate of the water could lead to a reasonable value for solution
gas-water ratio by equating it to the producing gas-water ratio. Interpretation could be
complicated by not knowing for certain that the bottom-hole pressure was above the
bubble point of the formation water. As previously mentioned, if the reservoir pressure
drops below the bubble point pressure of the formation water, the results could be
impacted by potential two-phase flow in the formation that could lead to producing gas-
water ratios that might not be representative of the solution gas-water ratio for the
formation water.
It is also possible that one might note when gas first starts being produced from
the casing-tubing annulus when production tubing and pump are installed in the well.
One could then place a backpressure on the well at the surface and consequently raise the
bottomhole producing pressure. If the bottom-hole pressure rises to a level that would be
above the bubble point of the formation water at bottom-hole conditions, the gas would
go back into solution and flow from the casing-tubing annulus would cease with the
desirable result that the fluids at the bottom of the hole would be a single phase. This
could lead to a fairly accurate estimate of solution gas-water ratio as determined from the
21

producing gas-water ratio with the risk that the re-solution of the gas in the water may be
in proportions not representative of the formation water.
As mentioned above, direct measurement of solution gas-water ratios can involve
separation and volumetric testing of the gas and water. The separation facilities through
which the produced fluids may be passed can be any convenient facilities. Several
separation facilities are considered in a document prepared by the Michigan Department
of Public Health (Keech and Gaber, 1982) hereby incorporated by reference. The
facilities can include those that are commercially available that are normally used for the
surface separation of reservoir fluids in the oil industry or perhaps modified to measure
quantities of fluids more precisely. If such facilities are not in place, they may not be
convenient because of the logistics of moving them from one place to another perhaps
because of their large size, etc. Facilities that may be convenient include: a bubble-pail
device and a separation barrel device.
The bubble-pail device is discussed by Keech and Gaber, 1982. Simply stated, the
bubble pail may be any suitable container (e.g., a five-gallon bucket) through which a
riser pipe may be mounted with a stand located some distance down on the riser pipe and
attached to it. At the top of the bucket may be located an outlet. The produced fluids
from the well or a portion of them may be routed through the riser pipe and allowed to fill
the bucket so that water is flowing from the outlet on the top of the bucket. Valves can be
adjusted upstream to achieve a manageable rate of flow through the bucket and that rate
can be determined by collecting a known volume of water flowing from the bucket over a
given period of time. Once the rate has stabilized through the bucket, a calibrated, open-
ended transparent vessel may be filled with water and inverted so that the vessel remains
completely filled with water with no air or gas pockets at the top (actually after inversion
the bottom of the vessel becomes the top). To make a measurement, simultaneously, the
inverted gas-collection vessel is moved over the top of the riser pipe and held in place
resting on the stand and a container is placed under the outlet of the bucket. Gas floats to
the top of the vessel and water goes out the opening of the vessel and into the bucket. At
some convenient point, both the vessel and the container may be withdrawn perhaps
simultaneously. By measuring the amount of water in the container and the amount of
gas in the vessel, an estimate of producing gas-water ratio can be made by dividing the
amount of gas in the vessel by the amount of water in the container and converting
22

everything to standard conditions. Although it is preferable, where possible, to route the
entire produced volume through the pail, it is not always possible, so a partial stream can
be diverted through it. Generally, the results from a partial stream and a full stream are
consistent, but the inventor has observed that on occasion, the results are somewhat
different. So, a full stream through the bucket may be recommended.
The other facility that may be convenient is a separation barrel with orifice flow
tester and water meter. This is a more robust, but somewhat less transportable, separator
that can be constructed from a 55-gallon drum. Again a riser pipe through which the
produced fluids will flow may be mounted and sealed so that the top of the riser pipe is
located about halfway to the top of the drum. A sight glass may be installed so that the
level of fluid coming into the drum can be maintained constant by controlling a drain
valve located near the bottom of the drum. At the top, an orifice well tester may be
located in the opening of the drum. Conditions may be allowed to stabilize and then the
water rate may be determined by any means (e.g. flow meters, measured volumes per unit
of time), and the gas rate may be determined through the orifice well tester. The ratio of
the gas rate to the water rate may then be converted to standard conditions giving the
producing gas-water ratio.
Regardless of the separation facility employed, it may or may not be desirable to
account for the amount of gas remaining in solution in the water at atmospheric
conditions. It may be desirable if extreme accuracy is desired or warranted or at very low
bubble points approaching atmospheric pressure. Usually, the amount of solution gas
contained in water is represented as a function of absolute pressure. The solution gas-
water ratio of this remaining gas can be added to the value determined above, if deemed
significant in any application before the next step is performed. If this is done,
temperature of the water in the separator and atmospheric pressure may also be recorded
at the site of the measurement. The value of this small amount of remaining gas can then
be estimated using measured data from a laboratory, Henry's law, or correlations as are
discussed throughout this document and particularly in the written description below. In
most applications adding in this small amount of gas remaining in solution at atmospheric
conditions, while theoretically important, may not be practically important and may beg
the accuracy.
23

In another embodiment, the invention can involve a determination of the bubble
point pressure for the formation water of the reservoir. In the event that a bottom-hole
sample of formation water is collected and analyzed and if part of the analysis was to
determine the bubble point pressure of the formation water at formation temperature and
pressure, then for the specific well from which the bottom-hole sample was taken, an
embodiment of the present invention may skip determining the solution gas-water ratio
and may go directly to determining CDP from the bubble point value. In fact the present
invention has discovered that the value of the bubble point pressure of the formation
water can be equated to the CDP of the coal.
The bubble point pressure of the formation water can also be estimated by a
variety of techniques in accordance with the present invention. If a bottom-hole sample
was collected and analyzed, and if the solution gas-water ratio as a function of absolute
pressure was obtained as part of the analysis, then the bubble-point pressure of the
formation water can be determined by finding the inverse of the functional relationship,
with the estimate of solution gas-water ratio as previously described. Mathematically,
this can be expressed as,

where bp is bubble point pressure of the formation water and Rsw is the solution gas-water
ratio. More practically, one can find the bubble point pressure of the formation water
from the point on the horizontal axis (bubble point pressure) corresponding to the point
where the value of the determined solution gas-water ratio intersects a curve drawn
through the experimentally measured data. Anticipated curve shapes can also be used.
Figure 1 shows a fictitious relationship between solution gas-water ratio and bubble point
pressure such as might be determined in the laboratory at a given temperature and
salinity. One enters the vertical axis at a point (arbitrarily shown as [1]) with the solution
gas-water ratio, goes horizontally until one reaches point [2], the intersection point with
the curve, and then moves vertically downward to determine the corresponding bubble
point pressure of the formation water at point [3]. In doing so, one is implicitly assuming
that the water to which a solution gas-water ratio is determined is not appreciably
dissimilar from the water analyzed in the laboratory (e.g., same temperature with similar
salt concentration, gas composition, etc.). In most cases, this will be a reasonable
24

assumption over fairly large geographical areas within a certain formation in a given
geological province. If it is believed that this assumption is not being met, then one risks
some accuracy. In such cases, one could have additional samples taken and analyzed. As
a somewhat less accurate alternative, water samples from nearby producing wells can be
quite easily obtained and sent to a laboratory where a relatively inexpensive and routine
analysis can yield salt concentration in the water. In many instances, such measurements
are required by state agencies anyway, so the data may be as close as the well file. Also,
temperatures of the formations can be readily obtained for a given area from correlations
with depth using an appropriate geothermal gradient or by direct measurement. Knowing
this range of salt concentrations and temperatures, one could request that the laboratory
prepare a family of curves similar to Figure 1 using this range as bounding values. Then,
one could determine the bubble-point pressure by using the appropriate curve or
interpolated value between bounding curves corresponding to the temperature of the
formation and salt concentration of the formation water from the well for which the
bubble point pressure is desired.
While the laboratory-derived curve(s) as discussed in the preceding technique has
(have) the advantage of using gases that may be close to the composition of the gas
contained in solution of any reservoir of interest and while the formation water can have
the correct salinity factors, obtaining such samples and analyses can require time and
additional expense. Taking this into consideration and realizing that CBM is mostly
methane, probably the preferred technique of determining bubble-point pressure of the
formation water is to assume that the gas is all methane and to use existing correlations if
reservoir temperatures and pressures are within the specified ranges of the correlation. If
reservoir temperatures and pressures are outside of the ranges of the correlation, then
according to the present invention extrapolated values of fits to these existing correlations
can be used. These correlations are quite prevalent in the literature. For a fairly complete
review of these correlations, see Whitson and Brule, 2000, Chapter 9. Two such
correlations are particularly appropriate to some embodiments of the present invention:
the McCain correlation (McCain, 1991, Equations 52-56) and the Amirijafari and
Campbell correlation (Amirijafari and Campbell, 1972).
The McCain correlation fits an original graphical and frequently referenced
correlation (see Culberson and McKetta, 1951) with a quadratic equation as a function of
25

absolute pressure and with coefficients that are functions of temperature in degrees
Fahrenheit. The correlation is believed accurate to within 5% for the graphical values
over pressures from 1,000 psia to 10,000 psia and temperatures from 100 to 340 degrees
Fahrenheit. Lending to the nonobvious character if the present invention, McCain
himself states that the correlation should not be used for pressures below 1000 psia.
Noteworthy is the fact that McCain also provides an equation (Equation 57) that takes
into consideration salinity of the formation water. In general, solution-gas decreases with
increasing salinity. Whether use with or without the salinity factor, the present invention
shows that the McCain correlation can in fact be used in conjunction with or as part of the
present invention to achieve the evaluation even though at pressures outside of the
recommended range.
The second correlation that can be beneficially used is that of Amirijafari and
Campbell (Amirijafari and Campbell, 1972). This includes data at a somewhat lower
pressure, but still not at the pressures low enough to address the needs of the present
invention. Figure 2 shows a plot derived from individual data points presented by
Amirijafari and Campbell. This data represents the solubility of pure methane in water
(mole fraction of methane in the water-rich phase) at a temperature of 100 degrees
Fahrenheit and for pressures between 600 and 5000 psia. In accordance with the present
invention, a curve has been generated through the data that is a statistical fit by a cubic
equation as a function of pressure with the intercept forced to be zero (the equation and
goodness of fit are shown in Figure 2). Since this data begins at 600 psia, use of this
correlation also involves extrapolation beyond the values of the data presented. One such
extrapolation is shown in Figure 3 with conversion of mole fraction to units of SCF/STB
as supported by the reference to Whitson and Brule, 2000. The significance of the
extrapolation can be understood by the fact that in the Powder River Basin, where the
invention taught here has been reduced to practice, all bubble points estimated by the
invention were below 600 psia. The extrapolation, therefore, has been used and is
valuable to estimate the bubble point of the formation water. While normally one
extrapolates data outside of its measured range at some risk to accuracy, the invention
involves techniques that can reduce the potential inaccuracies of an extrapolation. In
embodiments, it may involve the technique of utilizing an expected zero crossing point
where, at an absolute pressure of zero, no methane is assumed to remain in solution. It
can be noted that by forcing the curve to go through zero-zero, the fit of the curve through
the measured points is excellent (See Figure 2). In addition, there are theoretical methods
26

that can to some degree corroborate the results shown here. Actual data also shows that
this embodiment is fairly accurate. In the Powder River Basin this embodiment has been
tested in several wells by the inventor exclusively using the extrapolation in spite of the
fact that it is outside the range of the measured data, in spite of the fact that the
temperatures of the reservoir are typically less than 100 degrees Fahrenheit, in spite of the
fact that the formation waters of the PRB are not completely fresh, and in spite of the fact
that the gas composition is not entirely methane. In the wells where the reservoir pressure
has now dropped to a level where commercial quantities of CBM are now being
produced, using the bubble point determined in this manner has resulted in a reliable
prediction of CDP. Also, in wells using this technique of bubble point testing in
determining CDP, and, in turn, using the determined CDP to estimate gas content has
provided a reliable estimate of the gas content of the coal in wells where gas content was
measured on cores according to the more expensive and time consuming prior techniques.
A third method of correlation that can be beneficially used is that of theoretical
techniques. Estimates of solubility of gas in water for dilute solutions can be determined
by theoretical methods. These are also discussed in the reference to Whitson and Brule,
2000 hereby incorporated by reference. Figure 4 shows the comparison of the solution
gas-water ratio predicted by one of these methods, a theoretical methods based on
Henry's Law, with the extrapolation of the fit to publicly available data (an Amirijafari
and Campbell correlation) and a hybrid method discussed below. The closeness of the
curve generated by Henry's Law and the curve from the extrapolation of Amirijafari's
and Campbell's data is quite remarkable at pressures below 500 psia - pressures
previously thought to be outside the usable range of the data. Note that as pressure
increases, the solution becomes less dilute and the theoretical prediction resulting from
Henry's law eventually begins to deviate significantly from the measured data. This is
consistent with the theory of Henry's law. But in areas of lower pressures, regions where
the predicted CDP's fall below 500 psia, this method may have the most utility of all. In
fact its value may be understood by the facts that Henry's Law is simple to apply and the
fact that Henry's Law constants are readily available in the literature for a wide range of
temperatures (e.g., Perry and Green, 1997). When theoretical methods such as these are
employed, one can even reduce gas content calculations to a single equation as a function
of the solution gas-water ratio as determined above. For example, through the present
invention and for a given temperature, one could obtain, by interpolation if need be, the
27

appropriate Henry's law constant, adjust this constant to the appropriate units, solve for
pressure as a function of solution gas-water ratio and then substitute this expression into
the Langmuir equation resulting in an expression relating gas content directly calculable
as a function of one variable, the solution gas-water ratio.
Yet another embodiment may involve the use of an approximate correlation. In
particular, it should be understood that any combination of the above theoretical and
empirical correlations could be used. For example, Henry's Law may be viewed as
resulting in a straight line relationship between solution gas-water ratio and absolute
pressure and McCain's correlation may be understood as valid only as low as 1000 psia, it
can also be understood that these may not take into account salinity. Even in a salinity
based correlation, the inventive technique of utilizing an expected zero crossing point
where, at an absolute pressure of zero, no methane is assumed to remain in solution can
be applied with success. Specifically, if salinity is deemed an important consideration,
one could combine these ideas by evaluating the McCain correlation adjusted for salinity
at the edge of the range of applicability of the correlation and then use an equation of a
straight line connecting this point running through the origin. Applying this procedure
with a salinity of zero results in the curve such as shown in Figure 4 and identified in the
legend as the "Hybrid (McCain endpoint)" method. This, too, can be used in
embodiments of the present invention.
A significant aspect of the present invention is its realization that the bubble point
pressure of an entirely different substance, namely the formation water, can be used to
inductively quantify the critical desorption pressure of the coal. As discussed above,
there appears to be no clear recognition that the bubble point pressure of the formation
water can be equated to and is the same as the critical desorption pressure of the coal.
Perhaps surprisingly, the present inventor has demonstrated that the bubble point pressure
of the formation water is the critical desorption pressure of the coal. This fundamental
realization permits the easy determination of the CDP and its use several applications of
much value.
Perhaps of most economic importance, by the highly simplified determination of
CDP, gas content can be more easily determined. One of the most valuable applications
is to determine CDP by the invention as taught here and then use the value obtained to
28

estimate gas content of the coal. In one embodiment, this gas content can be estimated by
using publicly available, predetermined isotherm data. In most coals where CBM
deposits are of commercial interest, some evaluation of the deposits has been performed
by government agencies holding interest in the deposits. As part of that evaluation, gas
contents and isotherms are usually measured and available to the public. As mentioned
above, such is the case in the PRB where the BLM has constructed an average
synthesized isotherm from isotherms measured on some 40 samples. Figure 5, prepared
by the inventor, shows approximate fits of the Langmuir equation to the isotherms
determined by the BLM. The Langmuir equations were found by extracting two points
from the curves and determining the Langmuir volume and pressure by algebra. To
obtain an estimate of expected gas content using this embodiment, one may simply enter
the curve with the CDP on the horizontal curve and determine the value of the gas content
from the vertical axis corresponding to the value of CDP from the middle curve, i.e. GC =
f(CDP), where GC is gas content. Also, as alluded to above, the BLM has reflected in
their figures the uncertainty associated with the data by showing the curves representative
of one standard deviation above and below the mean. These have also been
approximately fit by using two points by the inventor with the Langmuir equation. From
the curves, it is obvious that as the CDP becomes smaller the absolute error becomes
smaller so that at very low CDP's, one can even expect, with very little risk, that little gas
will be ultimately recoverable. So, if a low CDP, close to zero, is determined by the
invention taught here, the prospect for gas recovery from the coal may be viewed as
almost nil. For example, using the BLM average isotherm with the CDP determined by
the invention taught here and using the Amirijafari and Campbell curve in Figure 4
resulted in estimates of gas contents for two wells in the PRB of 5.2 and 8.1 SCF/Ton.
For the conditions in these wells (including high initial reservoir pressure and low CDP
implying long dewatering periods), such values show rather easily that these two wells
are not likely prospects for commercial CBM production.
In another embodiment, this gas content can also be estimated by using
correlations based on rank of coal using coal-type ranked data. A published set of curves
such as shown in Figure 6 that show the relationship between maximum producible
methane and depth of coal with rank of the coal as a parameter can be used in this
embodiment (see Eddy et al, 1982). As a first approximation, one could convert these
curves to functions of absolute pressure by assuming a fresh-water, hydrostatic gradient
29

(0.433 psi/ft), multiplying this number by the depth, and by adding atmospheric pressure
to the result. As such, these would then represent an inexpensive isotherm that could be
used to estimate gas content if the rank of the coal is known. For example, in the PRB,
the gas-containing coal is predominantly, if not exclusively, subbituminous in rank.
Constructing an isotherm according to the present invention with use of Eddy's curve for
subbituminous C coals results in Figure 7. In practice, the plot in Figure 7 was
constructed by pulling two points off the graph of Figure 6, converting the abscissa to
psia and determining the Langmuir volume and pressure from simultaneous solution of
the equation of these two unknowns. Making this embodiment less intuitive is the fact
that the plot of Figure 6, as will be noted, for such low gas-content coals could result in
highly subjective interpretations. With no particular attempt to fit the data, however, the
gas contents resulting from the use of this isotherm embodiment and the invention
embodiment turned out to be 13.7 and 18.7 SCF/ton - which compare respectively to the
ones determined in the preceding paragraph. While the two sources of isotherms may
appear to give results that are significantly different, in the PRB where the range of gas
contents can be 0 to 100+ SCF/ton, both of these results would likely result in the same
conclusion, i.e. that the coals in these wells have gas contents on the low end of the range
for the PRB. Also, it can be noted that the approach using coal rank to generate the
isotherm will also allow one to make the conclusion that the second coal is relatively
better than the first and this could be valuable to know as explained next.
In yet a further embodiment, merely relative gas content can be estimated even if
the only thing that is known in a given area is an approximate gas content at a given
pressure, in such an embodiment, a fictitious isotherm could be constructed just by
sketching in an arbitrary shape, with use of the technique of going through the given
pressure and the origin of zero gas content at zero absolute pressure. For example, a
source for such data might be a well where gas contents had been measured in a
laboratory, but the operator may not have requested that an isotherm be measured as part
of the laboratory measurements. Associating the measured gas content with the CDP
determined by the invention taught here could help in defining the fictitious isotherm with
increased accuracy by requiring it to go through this one measured point. Carrying this
approach one step further, if there happened to be yet another well in close proximity
where another gas content measurement had been determined and also a CDP
determination made by the invention taught here, then, if the gas content and CDP were
30

uniquely different from the first, one could construct an isotherm that could conceivably
be better than the one determined with only a single point. In some embodiments, two
non-zero points may be all that are required to adequately define an isotherm. In these
manners, determining CDP for a number of exploratory wells in a given geologic area by
the invention taught here and estimating the gas content using the fictitious isotherm
could then provide a relative ranking of prospects for development with those having the
highest gas contents having the highest rank. Similarly, even without any gas contents
measured at all, if the CDP's were measured on a number of exploratory wells using the
invention taught here in a given geologic area, just arranging the measured CDP's in
order of highest to lowest CDP could give a working list of developmental prospects with
those having the highest CDP's being developed first.
Table 1 shows a number of comparisons between the uses of the various
techniques of determining gas contents using the methodology discussed above and the
invention taught here to determine CDP. Merely as a point of reference, Table 1 also
shows results from gas contents determined from cores for the two wells in the PRB. As
discussed above, the core-measured data should not necessarily be regarded as the truth
because of the inherent problems associated with its estimation. Nevertheless, the results
show that the invention as taught here can provide remarkable consistency with measured
data from cores but at a drastically reduced expense — particularly when data, like the
BLM data is available for a given region. As mentioned, at higher CDP's the error in the
approximation for gas content may increase. In spite of this, the inventor has noted,
however, that the predicted CDP at higher resulting values of CDP using the invention
taught here and the BLM average curve was an accurate predictor of the reservoir
pressure when the wells subsequently started producing gas. Gas contents determined by
using the average BLM isotherm and the invention taught here to determine CDP's have
resulted in estimates of gas contents from zero to 60 SCF/ton in about 20 wells where the
method has been applied.
As should be understood from the above, the embodiments relative to the
characterization of the reservoir or even the determination of gas content in accordance
with the present invention can be highly varied. One may simply involve a prediction of
how much drop in reservoir pressure is likely to be required by dewatering before gas is
produced. Once the CDP is estimated by the invention taught here and with a
31

measurement of initial pressure of the reservoir, an estimate can be determined of how
much water must be produced before commercial quantities of gas can be produced, an
estimated dewatering value. This may be done by approximate reservoir engineering
calculations, or in more sophisticated calculations, by a reservoir simulator. Obviously
having to dewater for long periods of time without producing any gas can be a major
detriment to positive economics of any project under consideration.
Another embodiment may involve a determination of current saturation character
or saturation state of a coal used for gas storage or sequestration of harmful greenhouse
gases like carbon dioxide. By using the invention taught here and an isotherm or multi-
component isotherm representative of the gas(es) being stored or sequestered in an
undersaturated coal, one could estimate the current saturation state of the coal. This could
be valuable so that an estimate could be made as to when the storage reservoir would
effectively be filled up (i.e. when it would become saturated). Similarly the invention as
taught here could be used in determining the saturation state of the formation after a
period of injection of displacing gases such as are used in Enhanced Coalbed Methane
(ECBM) recovery processes (Puri and Stein, 1989).
Challenging situations can also be addressed in some embodiments. For example,
in reservoirs with low permeability or low permeability wells, an issue may arise
respective of produced wells. In the immediate vicinity of the wellbore, the reservoir
pressure could be very low from producing at low bottom hole pressure. The reservoir
pressure usually increases very rapidly away from the wellbore due to the typical pressure
profile associated with radial flow. It is possible that a portion of the reservoir near the
well could have been drawn below a CDP of the coal, for a period long enough to de-gas
to a certain degree. Detecting when de-gassing is occurring may be desirable and, if not
adequately accounted for, can be missed. In time, de-gassing could deplete the coal in the
immediate vicinity of the well. If the well is shut-in long enough for the water and the
coal to equilibrate, a determined CDP may be artificially low. The determined CDP may
not be representative of the CDP of the bulk of the coal some distance away from the
wellbore. With time, natural or induced groundwater flow may resaturate the coal to at or
near a CDP, such as a CDP prior to production; but if, for example, the formation is
'tight' so as to prevent much groundwater flow, such as may be due to typically small
gradients, and also if the period of shut-in is long, then a measured CDP may not be
32

representative of the CDP of the coal of the reservoir, as may be the case when the well is
returned to production potentially for testing. Embodiments of the present invention may
be use to address unrepresentative CDP determinations. Accordingly, as features of some
embodiments, producing a well at small drawdown for a period of time (perhaps a week,
or a producing period that may be otherwise longer than a traditionally expected
production) after a period of quiescence or non-production may be used. Water coming
from the bulk of the formation will likely be moving rapidly through the volume
immediately next to the wellbore and what little CBM that may be lost to the highly
undersaturated coal immediately near the wellbore may not significantly impact the
determinations of the present invention and may even be ignored. Eventually, the coal
near the wellbore will resaturate to at or near an original CDP allowing equilibrium
methane conditions to be established at the well bottom; but in accordance with the
present invention, it may not be necessary to wait until full resaturation occurs before
testing. Furthermore, and if desired, several tests could be conducted with time until the
CDP stops increasing and in a manner that affirmatively allows pressure to rebuild, not
mere have it happen incidentally.
Yet another embodiment relative to the characterization of the reservoir in
accordance with the present invention may be the determination of the economic viability
of continuing to produce water from existing producers, more generally the inclusion of
an economic factor in the characterization. Many existing production wells have been
producing water for years with the operators not knowing whether these wells will ever
produce economic quantities of CBM. Threshold values or, more generally, screening
criteria can be used that incorporate a variety of concerns into an economic viability or
other analysis, including individually or in concert, but not limited to: a screening
criterion based upon a reservoir pressure, a screening criterion based upon a permeability
of the reservoir, a screening criterion based upon the apparent critical desorption pressure
of coal in the reservoir, a screening criterion based upon the estimated dewatering needs
of the reservoir, a screening criterion based upon the degree of undersaturation of the coal
in the reservoir, a screening criterion based upon current or projected prices of gas, and
even a set value of gas content. These may also be particularly suited to computer
analysis or automated modalities and may be used not just for producers, but for
leaseholders, bankers or other persons interested in the productive capabilities or in the
33

valuation of a particular property. The invention taught here can also be used with
existing producers that have yet to produce commercial quantities of CBM.
In one embodiment of the present invention, a single production test of the well
can be accomplished in usually less than one day and immediately if the well has been
produced for some period ahead of testing (e.g. a producing well where the pressure of
the reservoir has not dropped below the CDP). Typically, in a new well, one day is
sufficient for the well to displace foreign fluids introduced during drilling and completion
and to produce a stream of water representative of the formation water, but if not, the well
can be run until the solution gas-water ratio becomes relatively constant with repeated
measurements. Thus, the invention may lead to a quicker determination of CDP than
could be obtained from coring methods and analysis. In turn, the CDP obtained by
applying the invention taught here can be used in conjunction with representative
isotherms of the area being investigated to make an accurate and quick determination of
gas content of the coal relative to the months that coring and core analysis might take to
arrive at the same result.
In applying the present invention, it may be noted that results may even be more
objectively reliable than a localized testing methodology such as coal sampling since the
mixing of the formation water surrounding adjacent coals tends to average out differences
normally observed in results obtained by sample selection during coring and removes the
subjectivity associated with sample selection in core analysis. The results may also be
more reliable because the formation water is coming primarily from the same coal that
will ultimately be the gas-productive coal.
In addition, the present invention can address the problem identified above where
multiple wells must be drilled in a pilot. This can even be eliminated because when the
invention taught here is employed, the same information can be obtained from a short test
from a single well or short tests of a few wells thus eliminating millions of dollars in
development costs and months, in some cases years, of attempts at dewatering to bring
the reservoir pressure below its CDP so that gas can be produced in commercial quantities
and a determination made of the value of the resource.
34

When the invention taught here is employed, a good estimate can be made of the
existing gas content of the reservoir thus allowing an economic evaluation of the coal
immediately after the well is drilled or, in one application, even while the well is being
drilled and an informed decision can be made regarding whether additional development
wells should be drilled.
When the invention taught here is used, one may not have to worry about the state
of equilibrium of the fluids in the borehole because the invention taught here can provide
a way of checking to see if the fluid being tested is representative of formation water.
Additionally it should be understood that any of the above methods can be
embodied and encoded in a computer program to further simplify and to some degree
even automate the evaluation methods employed. It also may comprise a sampling
apparatus performing any or all of the above aspects as well as the products produced by
any or all of these aspects.
As can be easily understood from the foregoing, the basic concepts of the present
invention may be embodied in a variety of ways. It involves both determination,
evaluation, and characterization techniques as well as systems, plurality of apparatus,
assemblies, and devices to accomplish the appropriate determination, evaluation, and
characterization. In this application, the techniques are disclosed as part of the results
shown to be achieved by the various methods. Devices may be encompassed that
perform any of these as well. While some methods are disclosed, it should be understood
that these may be accomplished by certain devices and can also be varied in a number of
ways. Importantly, as to all of the foregoing, all of these facets should be understood to
be encompassed by this disclosure.
The discussion included in patent is intended to serve as a basic description. The
reader should be aware that the specific discussion may not explicitly describe all
embodiments possible; many alternatives are implicit. It also may not fully explain the
broad nature of the invention and may not explicitly show how each feature or element
can actually be representative of a broader function or of a great variety of alternative or
equivalent elements. Again, these are implicitly included in this disclosure. Where the
invention is described in method-oriented terminology, each step may be performed by a
35

device, component, or element. Apparatus claims may also be included for the methods
described. Neither the description nor the terminology is intended to limit the scope of
the claims that will be included in a full patent application.
It should also be understood that a variety of changes may be made without
departing from the essence of the invention. Such changes are also implicitly included in
the description. They still fall within the scope of this invention. It should be understood
that this disclosure is intended to yield a patent covering numerous aspects of the
invention both independently and as an overall system and in both method and apparatus
modes.
Further, each of the various elements of the invention and claims may also be
achieved in a variety of manners. This disclosure should be understood to encompass
each such variation, be it a variation of an embodiment of any apparatus embodiment, a
method or process embodiment, or even merely a variation of any element of these.
Particularly, it should be understood that as the disclosure relates to elements of the
invention, the words for each element may be expressed by equivalent apparatus terms or
method terms — even if only the function or result is the same. Such equivalent, broader,
or even more generic terms should be considered to be encompassed in the description of
each element or action. Such terms can be substituted where desired to make explicit the
implicitly broad coverage to which this invention is entitled. It should be understood that
all actions may be expressed as a means for taking that action or as an element which
causes that action. Similarly, each physical element disclosed should be understood to
encompass a disclosure of the action which that physical element facilitates. Regarding
this last aspect, as but one example, the disclosure of "separation facilities" should be
understood to encompass disclosure of the act of "separating" -- whether explicitly
discussed or not -- and. conversely, where there is disclosure of the act of "separating",
such a disclosure should be understood to encompass disclosure of a "separation facility"
and even a "means for separating." Such changes and alternative terms are to be
understood to be explicitly included in the description.
Any patents, publications, or other references mentioned in this application for
patent are hereby incorporated by reference. In addition, as to each term used it should be
understood that unless its utilization in this application is inconsistent with such
36

interpretation, common dictionary definitions should be understood as incorporated for
each term and all definitions, alternative terms, and synonyms such as contained in the
Random House Webster's Unabridged Dictionary, second edition are hereby incorporated
by reference. Finally, all references listed in the Information Disclosure Statement or
other information statement filed with the application are hereby appended and hereby
incorporated by reference; however, as to each of the above, to the extent that such
information or statements incorporated by reference might be considered inconsistent
with the patenting of this/these invention(s), such statements are expressly not to be
considered as made by the applicant(s).
Thus, the applicant should be understood to have support to claim at least: i) each
of the determination, characterization, and evaluation systems, plurality of apparatus,
assemblies, and devices as herein disclosed and described, ii) the related processes and
methods disclosed and described, iii) similar, equivalent, and even implicit variations of
each of these systems, plurality of apparatus, assemblies, and devices, processes and
methods, iv) those alternative designs which accomplish each of the functions shown as
are disclosed and described, v) those alternative designs and methods which accomplish
each of the functions shown as are implicit to accomplish that which is disclosed and
described, vi) each feature, component, and step shown as separate and independent
inventions, vii) the applications enhanced by the various systems or components
disclosed, viii) the resulting products produced by such systems or components, ix)
methods and systems, plurality of apparatus, assemblies, and devices substantially as
described hereinbefore and with reference to any of the accompanying examples, x) the
various combinations and permutations of each of the elements disclosed, xi) each
potentially dependent claim or concept as a dependency on each and every one of the
independent claims or concepts presented, xii) processes performed with the aid of or on
a computer as described throughout the above discussion, xiii) a programmable apparatus
as described throughout the above discussion, xiv) a computer readable memory encoded
with data to direct a computer comprising means or elements which function as described
throughout the above discussion, xv) a computer configured as herein disclosed and
described, xvi) individual or combined subroutines and programs as herein disclosed and
described, xvii) the related methods disclosed and described, xviii) similar, equivalent,
and even implicit variations of each of these systems and methods, xix) those alternative
designs which accomplish each of the functions shown as are disclosed and described, xx)
37

those alternative designs and methods which accomplish each of the functions shown as
are implicit to accomplish that which is disclosed and described, xxi) each feature,
component, and step shown as separate and independent inventions, and xxii) the various
combinations and permutations of each of the above. In this regard it should be
understood that for practical reasons and so as to avoid adding potentially hundreds of
claims, the applicant has presented claims with initial dependencies only. Support should
be understood to exist to the degree required under new matter laws -- including but not
limited to United States Patent Law 35 USC 132 or other such laws-- to permit the
addition of any of the various dependencies or other elements presented under one
independent claim or concept as dependencies or elements under any other independent
claim or concept.
To the extent that insubstantial substitutes are made, to the extent that the
applicant did not in fact draft any claim so as to literally encompass any particular
embodiment, and to the extent otherwise applicable, the applicant should not be
understood to have in any way intended to or actually relinquished such coverage as the
applicant simply may not have been able to anticipate all eventualities; one skilled in the
art, should not be reasonably expected to have drafted a claim that would have literally
encompassed such alternative embodiments.
Further, the use of the transitional phrase "comprising" is used to maintain the
"open-end" claims herein, according to traditional claim interpretation. Thus, unless the
context requires otherwise, it should be understood that the term "comprise" or variations
such as "comprises" or "comprising", are intended to imply the inclusion of a stated
element or step or group of elements or steps but not the exclusion of any other element
or step or group of elements or steps. Such terms should be interpreted in their most
expansive form so as to afford the applicant the broadest coverage legally permissible.
38

-39-
We Claim
1. A method of evaluating an undersaturated coalbed methane reservoir comprising
the steps of:
a. accessing a well admitted to an undersaturated coalbed methane reservoir;
b. sampling formation water from said undersaturated coalbed methane
reservoir;
c. conducting a test based on said formation water sample;
d. inductively quantifying a methane content characteristic of sorbed methane
that is sorbed in a solid formation substance from said water sample; and
e. characterizing said coalbed methane reservoir based upon said inductively
quantified methane content characteristic.
2. A method of evaluating an undersaturated coalbed methane reservoir comprising
the steps of:
a. accessing an existing unproductive well admitted to a coalbed methane
reservoir;
b. sampling formation water from said coalbed methane reservoir;
c. conducting a test based on said formation water sample; and
d. estimating an economic factor for commercial production from said well
based upon said step of conducting a test based on said formation water
sample.
3. A dynamic method of surface sampling subsurface formation water comprising
the steps of:
a. accessing a well admitted to an undersaturated coalbed methane reservoir;
b. assuring that a formation water sample is representative of fluid from said
undersaturated coalbed methane reservoir;
c. initially sampling formaiion water from said undersaturaled coalbed
methane reservoir;
d. conducting an initial test based on said initial formation water sample:
e. additionally sampling formation water from said undersaturated coalbed
methane reservoir;
f. conducting a similar test based on said additional formation water sample;
AMENDED PAGE

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g. comparing results of said initial sampling and said additional sampling;
and
h. achieving a constancy in said comparing the results through alteration of
actions affecting said step of sampling formation water from said
undersaturated coalbed methane reservoir.
4. A method of evaluating an undersaturated methane, reservoir comprising the steps
of:
a. accessing a well admitted to an undersaturated methane reservoir;
b. sampling formation water from said undersaturated methane reservoir;
c. conducting a test based on said formation water sample;
d. inductively quantifying a methane content characteristic of sorbed methane
that is sorbed in a solid formation substance from said water sample; and
e. characterizing said methane reservoir based upon said inductively
quantified methane content characteristic.
5. A method of evaluating an undersaturated methane reservoir as described in claim
k wherein said well has a well bottom and wherein said step of sampling
formation water from said undersaturated methane reservoir comprises the step of
collecting a single phase fluid from about said well bottom.
6. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of sampling formation water from said undersaturated
methane reservoir comprises the step of sampling formation water until a gas-
water ratio of said water is constant.
7. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of sampling formation water from said undersaturated
methane reservoir comprises the step of contained sampling said formation water.
8. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of conducting a test based on said formation water sample
comprises the step of on-site testing of said formation water.
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9. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of conducting a test based on said formation water sample
comprises the step of determining a gas-water ratio of said formation water.
10. A method of evaluating an undersaturated methane reservoir as described in claim
9 wherein said step of determining a gas-water ratio of said formation water
comprises the step of directly testing said gas-water ratio of said formation water.
11. A method of evaluating an undersaturated methane reservoir as described in claim
10 wherein said step of directly testing said gas-water ratio of said formation water
comprises the step of on-site testing of said formation water.
12. A method of evaluating an undersaturated methane reservoir as described in claim
11 wherein said step of on-site testing of said formation water comprises the step
of conducting a surface test of said formation water.
13. A method of evaluating an undersaturated methane reservoir as described in claim
9 wherein said step of determining a gas-water ratio of said formation water
comprises the step of testing the total gas content of said formation water.
14. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of conducting a test based on said formation water sample
comprises the step of determining a bubble point of said formation water.
15. A method of evaluating an undersaturated methane reservoir as described in claim
14 wherein said step of determining a bubble point of said formation water
comprises the step of directly testing said bubble point of said formation water.
16. A method of evaluating an undersaturated methane reservoir as described in claim
15 wherein said step of directly testing said bubble point of said formation water
comprises the step of on-site testing of said formation water.
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17. A method of evaluating an undersaturated methane reservoir as described in claim
16 wherein said step of directly testing said bubble point of said formation water
comprises the step of conducting a surface test of said formation water.
18. A method of evaluating an undersaturated methane reservoir as described in claim
17 wherein said step of directly testing said bubble point of said formation water-
comprises the steps of:
a. releasing pressure from a contained volume; and
b. observing a change resulting from said release of pressure.
19. A method of evaluating an undersaturated methane reservoir as described in claim
18 wherein said step of sampling formation water from said undersaturated
methane reservoir comprises the step of contained sampling said formation water.
20. A method of evaluating an undersaturated methane reservoir as described in claim
14 wherein said step of inductively quantifying a methane content characteristic of
sorbed methane that is sorbed in a solid formation substance from said water
sample comprises the step of using a bubble point of said formation water to imply
a critical desorption pressure of said undersaturated methane reservoir.
21. A method of evaluating an undersaturated methane reservoir as described in claim
14 wherein said step of determining a bubble point of said formation water
comprises the step of directly testing said bubble point of said formation water.
22. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of conducting a test based on said formation water sample
comprises the step of capturing gas from said undersaturated methane reservoir.
23. A method of evaluating an undersaturated methane reservoir as described in claim
22 wherein said step of conducting a test based on said formation water sample
comprises the step of separating gas and formation water from said well.
24. A method of evaluating an undersaturated methane reservoir as described in claim
23 wherein said step of separating gas and formation water from said well
comprises the step of utilizing a bubble pail apparatus on site.
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25. A method of evaluating an undersaturated methane reservoir as described in claim
23 wherein said step of separating gas and formation water from said well
comprises the step of utilizing a separation barrel apparatus and an orifice well
tester on site.
26. A method of evaluating an undersaturated methane reservoir as described in claim
23 wherein said step of conducting a test based on said formation water sample
comprises the steps of:
a. factoring in a surface temperature effect; and
b. factoring in a surface pressure effect.
27. A method of evaluating an undersaturated methane reservoir as described in claim
22 wherein said step of conducting a test based on said formation water sample
comprises the step of factoring in composition of gases obtained from said well.
28. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of inductively quantifying a methane content characteristic of
sorbed methane that is sorbed in a solid formation substance from said water
sample comprises the step of inferring a critical desorption pressure for a methane-
containing solid from said step of conducting a test based on said formation water
sample.
29. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of inductively quantifying a methane content characteristic of
sorbed methane that is sorbed in a solid formation substance from said water
sample comprises the step of utilizing an inverse gas-water ratio functional
relationship.
30. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of characterizing said methane reservoir based upon said
inductively quantified methane content characteristic comprises the step of
determining a likely amount of methane production available from said well upon
production.
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31. A method of evaluating an undersaturated methane reservoir as described in claim
30 wherein said step of determining a likely amount of methane production
available from said well upon production comprises the step of utilizing an
inferred critical desorption pressure for a solid within said undersaturated methane
reservoir.
32. A method of evaluating an undersaturated methane reservoir as described in claim
31 wherein said step of characterizing said methane reservoir based upon said
inductively quantified methane content characteristic comprises the step of
utilizing a saturated methane isotherm for said undersaturated methane reservoir.
33. A method of evaluating an undersaturated methane reservoir as described in claim
32 wherein said step of utilizing a saturated methane isotherm for said
undersaturated methane reservoir comprises the step of utilizing data
representative of a Langmuir isotherm.
34. A method of evaluating an undersaturated methane reservoir as described in claim
33 wherein said step of utilizing data representative of a Langmuir isotherm
comprises the step of fitting a curve for a Langmuir isotherm to measured data for
said well.
35. A method of evaluating an undersaturated methane reservoir as described in claim
32 wherein said step of utilizing a saturated methane isotherm for said
undersaturated methane reservoir comprises the step of utilizing publicly
available, predetermined isotherm data.
36. A method of evaluating an undersaturated methane reservoir as described in claim
32 wherein said step of utilizing a saturated methane isotherm for said
undersaturated methane reservoir comprises the step of utilizing data determined
for another well within a reservoir area.
37. A method of evaluating an undersaturated methane reservoir as described in claim
32 wherein said step of utilizing a saturated methane isotherm for said
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undersaturated methane reservoir comprises the step of utilizing coal-type ranked
data.
38. A method of evaluating an undersaturated methane reservoir as described in claim
37 wherein said step of utilizing coal-type ranked data comprises the steps of:
a. converting from production values to create data representative of amount
of gas as a function of pressure;
b. determining appropriate Langmuir-type parameters;
c. applying said appropriate Langmuir-type parameters to said data;
d. creating an approximate gas-water functional relationship for said
formation water from said undersaturated methane reservoir; and
e. utilizing said approximate gas-water functional relationship for said
undersaturated methane reservoir in characterizing said undersaturaLed
methane reservoir.
39. A method of evaluating an undersaturated methane reservoir as described in claim
32 wherein said step of utilizing a saturated methane isotherm for said
undersaturated methane reservoir comprises the step of utilizing isotherm data for
a different well in a same reservoir area.
40. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of characterizing said methane reservoir based upon said
inductively quantified methane content characteristic comprises the step of
estimating a dewatering value for said reservoir.
41. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of characterizing said methane reservoir based upon said
inductively quantified methane content characteristic comprises the step of
determining an approximate drop in reservoir pressure needed for gas to be
produced from said well.
AMENDED PAGE

-46-
42. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of characterizing said methane reservoir based upon said
inductively quantified methane content characteristic comprises the step of
comparing said well to screening criterion.
43. A method of evaluating an undersaturated methane reservoir as described in claim
42 wherein said step of comparing said well to a screening criterion comprises the
step of comparing said well to a screening criterion selected from a group
consisting of: a screening criterion based upon a reservoir pressure, a screening
criterion based upon a permeability of said undersaturated methane reservoir, a
screening criterion based upon the apparent critical desorption pressure of solid in
said undersaturated methane reservoir, a screening criterion based upon the
estimated dewatering needs of said undersaturated methane reservoir, a screening
criterion based upon the degree of undersaturation of said undersaturated methane
reservoir, a screening criterion based upon current prices of gas, a screening
criterion based upon projected prices of gas, and a set value of gas content.
44. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of characterizing said methane reservoir based upon said
inductively quantified methane content characteristic comprises the step of
characterizing a plurality of wells prior to beginning commercial methane
production.
45. A method of evaluating an undersaturated methane reservoir as described in claim
4 wherein said step of inductively quantifying a methane content characteristic of
sorbed methane that is sorbed in a solid formation substance from said water
sample comprises the step of inductively quantifying a methane content
characteristic of sorbed melhane that is sorbed in coal.
46. Methane produced by use of any of the foregoing methods.
47. A method of evaluating an undersaturated methane reservoir comprising the steps
of:
a. accessing an existing unproductive well admitted to a methane reservoir;
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b. sampling formation water from said methane reservoir;
c. conducting a test based on said formation water sample; and
d. estimating an economic factor for commercial production from said well
based upon said step of conducting a test based on said formation water
sample.
48. A dynamic method of surface sampling subsurface formation water comprising
the steps of:
a. accessing a well admitted to an undersaturated methane reservoir;
b. assuring that a formation water sample is representative of fluid from said
undersaturated methane reservoir;
c. initially sampling formation water from said undersaturated methane
reservoir;
d. conducting an initial test based on said initial formation water sample;
e. additionally sampling formation water from said undersaturated methane
reservoir;
f. conducting a similar test based on said additional formation water sample;
g. comparing results of said initial sampling and said additional sampling;
and
h. achieving a constancy in said comparing the results through alteration of
actions affecting said step of sampling formation water from said
undersaturated methane reservoir.
AMENDED PAGE


The evaluation and assessment of geologic formations comprising undersaturated coalbed methane reservoirs. In some embodiments, the present invention provides for inductively quantifying critical desorption pressure of the solid in an undersaturated
coalbed methane reservoir from an unrelated substance, the formation water. By using these techniques, the characterization
of undersaturated coalbed methane reservoirs may be more quickly and economically made based upon a methane content characteristic
such as critical desorption pressure, gas content, and in some embodiments gas content as calculated from isotherm evaluation,
estimates of dewatering for production, and ratios of critical desorption pressure to initial reservoir pressure, among other possible
characteristics. The features of the invention may further have applicability in combination with conventional reservoir analysis,
such as coring, logging, reservoir isotherm evaluation, or other techniques.

Documents:

04975-kolnp-2007-abstract.pdf

04975-kolnp-2007-claims 1.0.pdf

04975-kolnp-2007-claims 1.1.pdf

04975-kolnp-2007-correspondence others.pdf

04975-kolnp-2007-description complete.pdf

04975-kolnp-2007-drawings.pdf

04975-kolnp-2007-form 1.pdf

04975-kolnp-2007-form 3.pdf

04975-kolnp-2007-form 5.pdf

04975-kolnp-2007-international exm report.pdf

04975-kolnp-2007-international publication.pdf

04975-kolnp-2007-international search report.pdf

4975-KOLNP-2007-(13-12-2012)-ABSTRACT.pdf

4975-KOLNP-2007-(13-12-2012)-AMANDED PAGES OF SPECIFICATION.pdf

4975-KOLNP-2007-(13-12-2012)-ANNEXURE TO FORM 3.pdf

4975-KOLNP-2007-(13-12-2012)-CLAIMS.pdf

4975-KOLNP-2007-(13-12-2012)-CORRESPONDENCE.pdf

4975-KOLNP-2007-(13-12-2012)-DESCRIPTION (COMPLETE).pdf

4975-KOLNP-2007-(13-12-2012)-DRAWINGS.pdf

4975-KOLNP-2007-(13-12-2012)-FORM-1.pdf

4975-KOLNP-2007-(13-12-2012)-FORM-2.pdf

4975-KOLNP-2007-(13-12-2012)-FORM-3.pdf

4975-KOLNP-2007-(13-12-2012)-FORM-5.pdf

4975-KOLNP-2007-(13-12-2012)-FORM-6.pdf

4975-KOLNP-2007-(13-12-2012)-OTHERS.pdf

4975-KOLNP-2007-(13-12-2012)-PETITION UNDER RULE 137.pdf

4975-KOLNP-2007-(19-10-2012)-CORRESPONDENCE.pdf

4975-KOLNP-2007-(19-10-2012)-OTHERS.pdf

4975-KOLNP-2007-ASSIGNMENT.pdf

4975-KOLNP-2007-CORRESPONDENCE OTHERS 1.1.pdf

4975-KOLNP-2007-FORM 13.pdf

4975-kolnp-2007-form 18.pdf

4975-KOLNP-2007-FORM 3-1.1.pdf

4975-KOLNP-2007-GPA.pdf


Patent Number 255521
Indian Patent Application Number 4975/KOLNP/2007
PG Journal Number 09/2013
Publication Date 01-Mar-2013
Grant Date 27-Feb-2013
Date of Filing 20-Dec-2007
Name of Patentee YATES HOLDINGS LLP
Applicant Address 105 SOUTH 4TH STREET ARTESIA, NEW MEXICO
Inventors:
# Inventor's Name Inventor's Address
1 CARLSON FRANCIS M 813 PIONEER AVENUE, GILLETTE, WYOMING 82718
PCT International Classification Number G01N 21/00
PCT International Application Number PCT/US2005/018323
PCT International Filing date 2005-05-24
PCT Conventions:
# PCT Application Number Date of Convention Priority Country
1 NA