Method and apparatus for the downhole compositional analysis of formation gases

A borehole tool analyzes the composition of gases flowing from a formation. The tool includes an optical fluid analyzer (OFA) and a gas analysis module (GAM). The OFA determines when fluid flowing into the tool has become substantially only gas. The gas is then diverted to the GAM, thereby avoiding the possibility of oil depositing itself on a optical window and interfering with a proper analysis. The GAM includes a near infrared ray light source, at least one photo-detector, a gas sample cell (or cells) having portions with different path lengths, each portion having an optical window, and fiber optics which direct light in first paths from the source to the sample cell, and from the sample cell to the photo-detectors. By providing cells with different path lengths, issues of dynamic range are obviated. The GAM also preferably includes a second optical path which goes directly from the light source to the photo-detectors and is used for canceling drift, and a third optical path which goes from the light source, through a known standard such as methane to the photo-detectors and is used for compensation of shifts in actual hydrocarbon peak locations or shifts in optical filter wavelengths. Analysis of the different hydrocarbon gas components of the gas stream is conducted by analysis of selected CH vibrational peaks in the 5700 cm.sup.-1 to 6100 cm.sup.-1 range.

BACKGROUND OF THE INVENTION 
The present invention is related to co-owned U.S. Pat. No. 4,994,671 to 
Safinya et al., No. 5,167,149 to Mullins et al., 5,201,220 to Mullins et 
al., No. 5,266,800 to Mullins et al., and No. 5,331,156 to Hines et al., 
all of which are hereby incorporated by reference herein in their 
entireties. 
1. Field of the Invention 
The present invention relates to the analysis of downhole borehole fluids. 
More particularly, the present invention relates to apparatus and methods 
for the downhole compositional analysis of gas in a geological formation 
through the use of spectroscopy. 
2. State of the Art 
Techniques for the qualitative and quantitative analysis of gas, liquid, 
and solid samples are well known. For example, as disclosed in U.S. Pat. 
No. 4,620,284 to R. P. Schnell, a helium-neon laser is used to provide 
photons of a 0.633 micron wave length which are directed at a sample 
flowing through a pipeline in an oil refinery. The resulting Raman 
scattering (scattering of light by molecular excitation) which comprises 
scattered light at different wavelengths than the incident light is then 
measured, and the measured spectrum is compared with previously obtained 
reference spectra of a plurality of substances. 
In U.S. Pat. No. 4,609,821 to C. F. Summers, especially prepared rock 
cutting containing at least oil from an oil-based mud are excited with UV 
radiation with a 0.26 micron wave length. Instead of measuring the Raman 
spectrum as is done in the aforementioned Schnell patent, in accord with 
the Summers disclosure, the frequency and intensity of the resulting 
excited waves (fluorescence) which are at a longer wavelength than the 
incident radiation are detected and measured. By comparing the fluorescent 
spectral profile of the detected waves with similar profiles of the oil 
used in the oil-based mud, a determination is made as to whether formation 
oil is also found in the rock cuttings. 
While the Summers and Schnell disclosures may be useful in certain limited 
areas, it will be appreciated that they suffer from various drawbacks. For 
example, the use of laser equipment in Schnell severely restricts the 
environment in which the apparatus may be used, as lasers are not 
typically suited to harsh temperature and/or pressure situations (e.g., a 
borehole environment). Also, the use of the Raman spectrum in Schnell 
imposes the requirement of equipment which can detect with very high 
resolution the low intensity scattered signals. The use by Summers of 
light having a 0.26 micron wavelength severely limits the investigation of 
the sample to a sample of nominal thickness. In fact, the Summers patent, 
while enabling a determination of whether the mud contains formation oil, 
does not permit an analysis of formation fluids in situ, and has no 
sensitivity to water. 
Those skilled in the art will appreciate that the ability to conduct an 
analysis of formation fluids downhole is extremely desirable. With that in 
mind, the assignee of this application has provided a commercially 
successful borehole tool, the MDT (a trademark of Schlumberger) which 
extracts and analyzes a flow stream of fluid from a formation in a manner 
substantially as set forth in co-owned U.S. Pat. No. 3,859,851 to 
Urbanosky U.S. Pat. No. 3,780,575 to Urbanosky which is hereby 
incorporated by reference herein in its entirety. The OFA (a trademark of 
Schlumberger), which is a module of the MDT, determines the identity of 
the fluids in the MDT flow stream and quantifies the oil and water content 
based on the previously incorporated related patents. In particular, 
previously incorporated U.S. Pat. No. 4,994,671 to Safinya et al. provides 
a borehole apparatus which includes a testing chamber, means for directing 
a sample of fluid into the chamber, a light source preferably emitting 
near infrared rays and visible light, a spectral detector, a data base 
means, and a processing means. Fluids drawn from the formation into the 
testing chamber are analyzed by directing the light at the fluids, 
detecting the spectrum of the transmitted and/or backscattered light, and 
processing the information accordingly (and preferably based on the 
information in the data base relating to different spectra), in order to 
quantify the amount of water, gas, and oil in the fluid. As set forth in 
previously incorporated U.S. Pat. No. 5,266,800 to Mullins, by monitoring 
optical absorption spectrum of the fluid samples obtained over time, a 
determination can be made as to when a formation oil is being obtained as 
opposed to a mud filtrate. Thus, the formation oil can be properly 
analyzed and quantified by type. Further, as set forth in the previously 
incorporated U.S. Pat. No. 5,331,156 to Hines et al., by making optical 
density measurements of the fluid stream at certain predetermined 
energies, oil and water fractions of a two-phase fluid stream may be 
quantified. 
While the Safinya et al., Mullins, and Hines et al. patents represent great 
advances in downhole fluid analysis, and are particularly useful in the 
analysis of oils and water present in the formation, they do not address 
in detail the gases which may be plentiful in the formation. The issue of 
in situ gas quantification is addressed in the previously incorporated 
U.S. Pat. Nos. 5,167,149 to Mullins et al., and 5,201,220 to Mullins et 
al., and in O. C. Mullins et al., "Effects of high pressure on the optical 
detection of gas by index-of-refraction methods", Applied Optics, Vol. 33, 
No. 34, pp. 7963-7970 (Dec. 1, 1994) which is also incorporated by 
reference herein in its entirety, where a rough estimate of the quantity 
of gas present in the flow stream can be obtained by providing a gas 
detection module having a detector array which detects light rays having 
certain angles of incidence. While rough estimates of gas quantities are 
helpful, it will be appreciated that compositional analysis of the gas 
would be more useful. In particular, gas analysis can be useful in 
determining which zones of a formation to produce, as gas zones with 
higher hydrocarbon content and with higher BTU content are more valuable 
than gas zones with lesser hydrocarbon content. In addition, it would be 
advantageous to be able to control the BTU content of the gas being 
produced without undergoing gas separation and recombination uphole, but 
rather by controlling quantities being produced from different locations 
in the borehole with advance knowledge of their respective BTU contents. 
Furthermore, downhole gas analysis could reveal the presence of noxious 
gases such as H.sub.2 S. Since H.sub.2 S is reactive with logging tool 
metals and is also reactive with basic materials contained in water based 
mud filtrate, analysis of samples carried to the surface often 
underestimate the noxious gas content of the samples. 
While techniques such as chromatography are routinely used for the analysis 
of gas in laboratories, the use of gas chromatography downhole is 
impractical due to several reasons. First, gas chromatography requires the 
use of a carrier gas flow stream whose volume far exceeds the sample gas 
volume. The handling of carrier gas within closed volumes of wireline 
tools represents a major problem especially considering that the formation 
gas pressures far exceed typical operating pressures of gas chromatography 
equipment. Second, handling of sample gas in gas chromatography equipment 
is difficult as very small volumes are used, and it is difficult to 
collect and transfer such small volumes from a large flow stream and 
guarantee representative samples. Third, the standard detectors for 
hydrocarbons in gas chromatography are a flame ionization detector and a 
thermal detector, both of which are impractical downhole because of the 
requirement of the maintenance of a stable flame downhole, and the wide 
variation in temperatures downhole. Finally, gas chromatography requires 
discrete measurements lasting several minutes which is undesirable in 
wireline applications. On the other hand, while spectroscopy has been used 
downhole for distinguishing between oil and water (in the near infrared 
spectrum), and for distinguishing among oils (in the visible spectrum), 
downhole spectroscopy has not been suggested for distinguishing between 
different hydrocarbon gases such as methane (CH.sub.4), ethane (having 
methyl components (CH.sub.3)), and higher hydrocarbons which contain 
methylene (CH.sub.2) for several reasons. First, because the density of a 
gas is a function of pressure, and because downhole pressures can vary by 
a factor of thirty or more, the dynamic range of the gas densities likely 
to be encountered downhole is extremely large. As a result, the dynamic 
range of the spectral absorption at frequencies of interest is also 
extremely large such as to make a measurement unfeasible; i.e., the 
sensitivity of the downhole spectroscopy equipment is typically incapable 
of handling the large dynamic ranges that are encountered. Second, due to 
fact that the condensed phase of hydrocarbon (oil) has a much higher 
density at downhole pressures than the gas phase, a thin film of liquid on 
the OFA window can yield significant absorption. Thus, interpretation of 
the results would yield a determination of a rich gas mixture, where no or 
little amounts of hydrocarbon gas was actually present. Third, the type of 
spectral analysis typically done uphole to distinguish among hydrocarbon 
gases cannot be done downhole. In particular, in uphole applications, 
individual gas constituents are detected by modulating a narrow band 
source on and off of mid-infrared absorption lines of the gas, where a 
resulting oscillation in absorption at each modulation frequency would 
indicate a positive detection of a particular gas. However, at the high 
pressures encountered downhole, not only are the narrow gas absorption 
spectral lines merged, but mid-infrared spectroscopy is hindered by the 
extreme magnitude of the absorption features. Fourth, spectrometers are 
typically sensitive to changes in temperature, and elevated temperatures 
encountered downhole can induce spectral changes of the gas sample, 
thereby complicating any data base utilized. 
SUMMARY OF THE INVENTION 
It is therefore an object of the invention to provide downhole apparatus 
and methods for quantitatively analyzing the composition of formation 
gases. 
It is another object of the invention to provide apparatus and methods for 
quantitatively analyzing hydrocarbon gases downhole using spectroscopy 
techniques. 
It is a further object of the invention to provide apparatus and methods 
which overcome dynamic range issues and permit spectral analysis downhole 
for quantitatively analyzing formation gases. 
It is an additional object of the invention to provide apparatus and 
methods which overcome other problems previously encountered in using 
spectral analysis downhole to quantitatively analyze formation gases. 
Another object of the invention is to provide apparatus and methods for 
quantitatively analyzing formation gases for BTU content. 
In accord with the objects of the invention, a,.downhole apparatus for 
analyzing formation gases is provided and generally comprises means for 
obtaining a flow of formation and borehole fluids through a path in the 
downhole apparatus, means for analyzing the obtained formation and/or 
borehole fluids for the presence of gas, diverter means for diverting 
formation gas into a separate stream, and a gas analysis module for 
analyzing the formation gas in that stream. According to the preferred 
embodiment of the invention, the gas analysis module includes a light 
source, a plurality of photo-detectors, a gas sample cell (or cells) 
having a plurality of portions with different path lengths and with a 
plurality of windows, and a fiber optic bundle for directing light from 
the light source to some of the windows, and from others of the windows to 
the photo-detectors. For example, a gas sample cell or cells preferably 
includes a portion with a 2 mm path length, another portion with a 4 mm 
path length, and a third portion with a 10 mm path length. If desired, 
pressure sensing means may be provided for controlling which optical 
information is provided to the photo-detectors. Alternatively, separate 
photo-detectors can be provided for each of the cells having different 
path lengths. 
By providing a diverter means and a separate gas analysis module, the 
likelihood of having a thin film of oil on the cell window is decreased 
substantially, thereby improving analysis results. Also, by providing one 
or more cells with different path lengths, issues of dynamic range are 
obviated, because where the pressure is higher, light will not be fully 
absorbed in the cell having a short path length, whereas where the 
pressure is lower, there will be some absorption in the cell having the 
longer path length. Thus, spectral analysis of gas will be possible 
downhole. 
According to another aspect of the invention, the gas analysis module is 
provided with a first optical path from the light source to the 
photo-detectors which goes through the cell or cells, a second optical 
path which goes directly from the light source to the photo-detectors, and 
third a optical path which goes from the light source, through a known 
standard to the photo-detectors. The known standard is preferably a 
natural gas with a known BTU content such as methane, although other 
standards could be utilized. The provision of the second path, which is 
known in the art, is used to cancel drift in the light source, detector, 
and electronics in order to provide a more robust spectral measurement. 
The provision of the third path through a known standard permits 
compensation for shifts in actual hydrocarbon peak locations or shifts in 
optical filter wavelengths, yielding an even more robust determination of 
sample properties in the downhole environment. 
In accord with yet another aspect of the invention, analysis of the 
different hydrocarbon gas components of the gas stream is conducted by 
analysis of selected CH vibrational peaks in the near infrared range (NIR) 
of 4000-10,000 cm.sup.-1 (as opposed to the mid-range used uphole), and 
preferably, specifically, particular peaks in the 5700 cm.sup.-1 to 6100 
cm.sup.-1 range. Thus, one or more optical filters are preferably provided 
in conjunction with the gas analysis module so that extraneous wavelengths 
outside of the desired range are not received at the photo-detectors.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
The instant invention is particularly applicable to both production logging 
and to borehole investigative logging. For purposes of brevity, however, 
the description herein will be primarily directed to borehole 
investigative logging, and the terms "borehole" and "borehole tool" should 
be read throughout the specification and claims to encompass a (cased) 
well and a tool used in a well, as well as in a borehole. Thus, a borehole 
tool 10 for testing earth formations and analyzing the compositions of 
fluids from the formation 14 in accord with the invention is seen in FIG. 
1. As illustrated the tool 10 is suspended in the borehole 12 from the 
lower end of a typical multiconductor cable 15 that is spooled in a usual 
fashion on a suitable winch (not shown) on the formation surface. On the 
surface, the cable 15 is preferably electrically coupled to an electrical 
control system 18. The tool 10 includes an elongated body 19 which 
encloses the downhole portion of the tool control system 16. The elongated 
body 19 also carries a selectively extendable fluid admitting assembly 20 
and a selectively extendable tool anchoring member 21 which are 
respectively arranged on opposite sides of the body. The fluid admitting 
assembly 20 is equipped for selectively sealing off or isolating selected 
portions of the wall of borehole 12 such that pressure or fluid 
communication with the adjacent earth formation is established. Also 
included with tool 10 are a fluid analysis module 25 through which the 
obtained fluid flows. The fluid may thereafter be expelled through a port 
(not shown) or it may be sent to one or more fluid collecting chambers 22 
and 23 which may receive and retain the fluids obtained from the 
formation. Control of the fluid admitting assembly, the fluid analysis 
section, and the flow path to the collecting chambers is maintained by the 
electrical control systems 16 and 18. 
Additional details of methods and apparatus for obtaining formation fluid 
samples may be had by reference to U.S. Pat. No. 3,859,851 to Urbanosky 
and U.S. Pat. No. 4,396,259 to Miller which are hereby incorporated by 
reference herein. It should be appreciated, however, that it is not 
intended that the invention be limited to any particular method or 
apparatus for obtaining the formation fluids. 
Turning to FIG. 2, a schematic diagram is seen of the preferred fluid 
analysis module 25 of FIG. 1. As seen in FIG. 2, the fluid analysis module 
25 includes an optical fluid analyzer 30, a flow diverter 35 with 
associated control line 38, a gas measurement cell 40, optional gas sample 
chambers 42a and 42b with associated valves 43a, 43b and control lines 
44a, 44b, and gas and fluid flow lines 45a, 45b, 45c, 45d, and 45e. The 
optical fluid analyzer 30, which receives fluids from the borehole and 
formation via fluid flow line 45a is preferably an analyzer such as shown 
and described in previously incorporated U.S. Pat. No. 4,994,671 to 
Safinya et al., No. 5,167,149 to Mullins et al., 5,201,220 to Mullins et 
al., No. 5,266,800 to Mullins et al., and No. 5,331,156 to Hines et al. 
Thus, the optical fluid analyzer 30 is capable of distinguishing between 
oil, water, and gas, and as set forth in U.S. Pat. No. 5,167,149 to 
Mullins et al., and U.S. Pat. No. 5,201,220 to Mullins et al., is capable 
of categorizing the fluid sample as high gas, medium gas, low gas, and no 
gas. When the fluid sample contains oil or water, the fluid sample is 
either optionally stored in sample fluid chambers (not shown), or expelled 
back into the borehole via fluid flow lines 45b and 45c. 
According to the preferred embodiment of the invention, upon determining 
that the fluid sample is substantially all gas (i.e., the fluid sample has 
a high gas content), the fluid analyzer 30 provides a control signal via 
control line 38 to the flow diverter which diverts the fluid sample via 
flow line 45d to the gas measurement cell 40 for analysis. While the flow 
diverter 35 can take many forms, preferably, it is simply embodied as an 
electronically controlled 2-way valve. After passing through the gas 
measurement cell 40, the gas may be sent to one or more gas sample 
chambers 43a, 43b, for storage. Valves 43a, 43b under control of the gas 
measurement cell 40 via control lines 44a, 44b are provided for that 
purpose. Alternatively, the gas may be passed via fluid flow line 45e back 
to fluid flow line 45c for the purpose of being expelled back into the 
borehole. If desired, backflow or check valves (not shown) may be provided 
to prevent borehole fluids from backing back into flow line 45d. 
Details of a first embodiment of the gas measurement cell 40 are seen in 
FIG. 3 where the cell 40 is seen to include a light source 52, a fiber 
optic bundle(s) 54 (with portions 54a, 54b1, 54b2, 54c1, 54c2, 54d1, 54d2, 
54e1 and 54e2), a variable path length vessel 60, including portions 60a, 
60b, and 60c, a photo-detector means 68, and a known sample 72. As 
indicated, gas received via control line 45d is provided to the vessel 60 
which includes portion 60a having a 2 mm path length (width), portion 60b 
having a 4 mm path length, and portion 60c having a 10 mm path length. The 
vessel 60 includes windows (not shown) through which the light is 
directed. The light is obtained from the light source 52 which preferably 
provides light in the near infrared (NIR) spectrum. If desired, an optical 
filter 78 may be provided at the light source to filter out light of other 
wavelengths. Regardless, light from the light source 52 is carried via 
optical fibers 54b1, 54c1, and 54d1 to the vessel 60, and light emerging 
from the vessel is carried by optical fibers 54b2, 54c2, and 54d2 to the 
photo-detector means 68. The photo-detector means 68 preferably includes 
several arrays of photo-detectors tuned to different frequencies of 
interest (as discussed below), but may include only a single 
photo-detector in conjunction with a filter wheel which permits a time 
division multiplexed determination of the frequency spectrum of the sample 
flowing through the vessel. Furthermore, it will be appreciated that, the 
light emerging from each of the portions 60a, 60b, and 60c may be sensed 
by different sets of photo-detectors, or as shown in FIG. 3, may be time 
division multiplexed to a single set of the photo-detectors through an 
aperture 81 which moves in conjunction with the entire photo-detector 
means 68. If desired, pressure sensing means may be provided for 
controlling which optical information is provided to the photo-detectors, 
as the cell portion having an appropriate path length for sensing the gas 
and providing a reading in a desired range will often be a function of 
pressure; i.e., the gas density (and hence absorbance per unit path 
length) varies as a function of pressure. In any event, it is generally 
preferable that the light provided to the photo-detector means 68 via 
fibers 54b2, 54c3, and 54d2 be separately sensed, because where the 
density of the gas is low, the light emerging from sample portion 60c may 
provide a desirable signal, but the light emerging from sample portion 60a 
will be too large and will not permit an appropriate analysis. 
As previously mentioned, light from the light source is also carried by 
fibers 54a for detection by the photo-detector means 68, and by fibers 
54e1 to the known reference sample 72, and from the reference sample by 
fibers 54e2 to the photo-detector means 68. The provision of fibers 54a 
for carrying light directly to the photo-detector means 68 is known in the 
art, and is used to cancel drift in the light source, detector, and 
electronics in order to provide a more robust spectral measurement. The 
provision of a third path through the known sample 72, however, permits 
compensation for shifts in actual hydrocarbon peak locations or shifts in 
optical filter wavelengths, yielding an even more robust determination of 
sample properties in the downhole environment. In particular, the known 
sample is preferably a natural gas (such as methane) with a known BTU 
content, although other known samples such as plastic films or methane 
clathrates or adducts can be utilized. With the known sample, shifts in 
actual hydrocarbon peak locations (discussed below) or shifts in optical 
filter wavelengths can be easily determined, thus permitting a relatively 
straightforward compensation for the unknown sample being analyzed. 
Turning to FIG. 4, a second embodiment of the gas measurement cell 40 which 
is similar to the embodiment of FIG. 3 is seen (with like or similar 
elements indicated by similar numerals increased by 100) where the cell 40 
includes a diverter(s) 151, a light source 152, a fiber optic bundle(s) 
154 (with portions 154a, 154b1, 154b2, 154c1, 154c2, 154d1, 154d2, 154e1 
and 154e2), vessels 160a, 160b, 160c of different path width, a 
photo-detector means 168, and a known sample 172. As indicated, gas 
received via control line 45d is diverted to lines 45d1, 45d2 and 45d3 and 
provided to the three separate vessels 160a, 160b, 160c. Vessel 160a 
preferably has a 2 mm path length (width), with vessel 160b preferably 
having a 4 mm path length, and vessel 160c preferably having a 10 mm path 
length. Each vessel includes windows (not shown) through which the light 
is directed. The light is obtained from the light source 152 which 
preferably provides light in the near infrared (NIR) spectrum. The NIR 
light from the light source 152 is carried via optical fibers 154b1, 
154c1, and 154d1 to the vessels 160a, 160b, and 160c respectively, and 
light emerging from the vessels is carried by optical fibers 154b2, 154c2, 
and 154d2 to a photo-detector means 168 which is comprised of several 
arrays of photo-detectors tuned to different frequencies of interest. A 
microprocessor (not shown) coupled to the sample photo-detector arrays is 
utilized to determine from which one or more of the arrays the frequency 
spectrum information is to be used. Light from the light source is also 
carried by fibers 154a to the photo-detector means 168, and by fibers 
154e1 to the known sample 172, and from the reference sample by fibers 
154e2 to the photo-detector means 168. If desired, separate 
photo-detectors means (not shown) can be provided for detecting light from 
fibers 154a and 154e2. 
In accord with yet another aspect of the invention, analysis of the 
different hydrocarbon gas components of the gas stream is conducted by 
analysis of selected CH vibrational peaks in the near infrared range (NIR) 
of 4000-10,000 cm.sup.-1, and preferably, specifically, particular peaks 
in the 5780 cm.sup.-1 to 6020 cm.sup.-1 range. More particularly, as seen 
in FIG. 5a, a low pressure low temperature optical density versus 
wavelength spectrum (e.g., ambient uphole T and P) of methane is seen. The 
high temperature (T=204.degree. C.), high pressure (P=10,000 psi) spectrum 
typical of downhole environments is seen in FIG. 5b. Comparing the two 
spectra, it is clear that the optical densities are much greater and much 
less defined (i.e., the peaks are spread) at the high pressures. In fact, 
the peaks around 6000 cm.sup.-1 (representing the two-stretch overtone), 
which in the low P, low T spectrum have optical densities of below 0.10, 
are very useful in the high P, high T situations. Alternatively, even 
peaks in the 7000 cm.sup.-1 and 8600 cm.sup.-1 ranges can be utilized at 
high pressures. Where high pressures are encountered, instead of utilizing 
vessels or cells of different path widths, it is possible to shift the 
frequency analysis to the different NIR peaks. 
Turning to FIG. 5c, a comparison of the NIR spectra of methane and heptane 
at high pressures (about 10,000 psi) is seen. The methane (CH.sub.4) shows 
shifted peaks compared to the heptane, which includes CH.sub.3 and 
CH.sub.2 groups (e.g., compare the two-stretch peak of methane at 6000 
cm.sup.-1 against the two-stretch peak of heptane at about 5806 cm.sup.-1 
which is a composite of the two-stretch CH.sub.2 peak at about 5782 
cm.sup.-1, and the two-stretch CH.sub.3 peaks at 5871 cm.sup.-1 and 5911 
cm.sup.-1). Also, turning to FIG. 5d, a comparison of the NIR spectra at 
between 5700 cm.sup.-1 and 6000.sup.-1 of the two-stretch overtones of 
n-heptane, n-nonane, and n-hexadecane (each having different CH.sub.2 and 
CH.sub.3 ratios) indicates that each has a peak at slightly different 
frequencies, and yields a slightly different optical density. Thus, it is 
evident that by obtaining a near infrared absorbance spectrum of a 
downhole gas at high temperatures and high pressures, a determination can 
be made as to the relative compositions of CH.sub.2, CH.sub.3, and 
CH.sub.4 in the gas, and hence the BTU content of the gas. 
Turning to FIG. 6, a broad statement of the method of the invention is seen 
in flowchart format. At 300, the NIR absorbance spectra of gas from a 
plurality of optical cells are obtained, as well as spectra from a 
standard and from a sample. Based on the spectral information obtained, as 
well as any other information such as downhole pressure and temperature 
(if available), a microprocessor located either downhole or uphole, at 
302, chooses which set or sets of information to process. At 304, the 
information is processed by fitting the data to known spectra which 
include CH.sub.2, CH.sub.3, and CH.sub.4 information, while correcting for 
temperature and pressure effects (preferably utilizing the standard and 
sample spectra) in order to obtain information regarding amounts of 
CH.sub.2, CH.sub.3, and CH.sub.4 in the gas stream. It will be appreciated 
that many different techniques can be used at step 304, including least 
mean squares fitting, multivariate analysis, etc. At 306, determinations 
relating to the gas content are logged as a function of depth in the 
borehole. These determinations which may include one or more of BTU 
content, and amounts of different hydrocarbons in the gas stream. The 
determinations may later be compared to actual gas samples obtained for 
confirmation purposes, and/or may be later used for production purposes to 
control the BTU content of a gas stream being produced from the well. 
It should be appreciated that information regarding other gases in the flow 
stream such as CO.sub.2 and H.sub.2 S which show vibrational absorption in 
the NIR range may also be obtained using the techniques set forth above. 
There have been described and illustrated herein apparatus and methods for 
the downhole compositional analysis of formation gases. While particular 
embodiments of the invention have been described, it is not intended that 
the invention be limited thereto, as it is intended that the invention be 
as broad in scope as the art will allow and that the specification be read 
likewise. Thus, while the invention has been described with reference to 
certain preferred apparatus for obtaining borehole and formation fluids, 
other apparatus could be utilized. Likewise, while certain preferred 
apparatus (the OFA) for determining when a flow stream has converted to 
substantially all gas has been described, other such apparatus could be 
utilized. In addition, while particular gas measurement cell arrangements 
were described, other arrangements could be utilized. Thus, instead of 
three cells or vessels of 2 mm, 4 mm, and 10 mm in width, different 
numbers of cells and/or different widths could be utilized advantageously. 
Also, while particular photo-detector arrangements were discussed, other 
spectral detector arrangements could be utilized. Further, instead of 
using both a direct path and a path through a known reference sample for 
correction, only the path through the known reference sample need be 
utilized. Further yet, while specific spectral peaks in the NIR spectrum 
(around 6000 cm.sup.-1) were discussed as being preferred for hydrocarbon 
analysis, it will be appreciated that other NIR peaks could be utilized. 
It will therefore be appreciated by those skilled in the art that yet 
other modifications could be made to the provided invention without 
deviating from its spirit and scope as so claimed.