petroleum engineering
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Measuring Methane Adsorption in Shales Using NMR
M.J. Dick1, C. Muir1, D. Veselinovic1, and D. Green1
1Green Imaging Technologies, Fredericton, NB, Canada
This paper was prepared for presentation at the International Symposium of the Society of Core
Analysts held in Vienna, Austria, 27 August – 1 September 2017
ABSTRACT
Despite the downturn in oil and gas prices, shale reservoir production continues and is
expected to grow as prices normalize. The total gas in place is a measure of the total natural
gas content in a shale which consists of both free gas in the porous spaces of the shales and
adsorbed gas on the surface of the shale matrix. The total gas in place is dependent on the
pore pressure and temperature and is vital to the profitable development of a shale
reservoir. Traditionally, gas isotherms are measured by exposing the core to helium and
methane at ever increasing pressure while tracking the volume of gas absorbed and
adsorbed. These experiments involve destruction of the core and provide no information
on the pore size distribution.
Free gas can be distinguished from adsorbed gas using NMR T2 distributions and thus the
total gas in place can be determined using NMR. This proves advantageous as the NMR
analysis can be completed without destruction of the shale core while providing pore size
distributions.
In this work, we present a method for measuring absorbed gas, adsorbed gas and total gas
content in shales using NMR. T2 measurements were taken over time after the introduction
of methane to both a sandstone and a shale. Methane absorption was observed in both
rocks, while adsorption was only observed in the shale. T1-T2 maps acquired in the shale
show that methane enters both organic and inorganic pores at similar rates.
INTRODUCTION
Shales are an important source of natural gas. Gas in shales can be absorbed as free gas in
the pore network or adsorbed on the surface of the organic material. Gas storage in shales
is characterized by plots of the quantity of adsorbed gas, free gas and/or total sorbed gas at
different pressures called isotherms [1].
The quantity of free and adsorbed gas is traditionally measured volumetrically using a
system of two cells, a reference cell and a sample cell, which are separated by a valve. A
crushed rock sample is placed in the sample cell. The reference cell is filled with a gas at a
known pressure. The valve is opened and the gas from the reference cell expands into the
sample cell and the pressures in the two cells equalize. The procedure is performed first
with a non-adsorbing gas, such as helium, to determine the void volume, or free gas
content, in the rock sample via the difference in temperature and pressure before and after
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opening of the valve between the two cells. The system is then vacuumed to remove the
gas, the reference cell is filled with an adsorbing gas and the procedure is repeated. When
the valve is opened and the adsorbing gas expands into the sample cell it will fill the void
volume and adsorb on the sample. Therefore, the amount of adsorption can be calculated
by subtracting the free gas content. The expansion of the gases is repeated at numerous
pressures to generate isotherms. The disadvantages of this traditional method are that the
sample is destroyed for the measurement, and no information is acquired on the size of the
pores occupied by the gas.
NMR can be used to generate gas isotherms. The advantages of NMR measurements are
that the samples will remain intact and the measurements will provide information on the
samples’ pore size distributions. Measuring gas in shales is challenging with NMR due to
the low hydrogen index of gas and the small pore volume of shales, both of which result in
low NMR signal. However, with recent advances in NMR hardware, gas measurements in
shales are possible. In this study we set out to use NMR to generate isotherms by
distinguishing the amount of free gas and adsorbed gas in a rock. This paper presents our
initial results of the measurement of total gas in place in a shale.
EXPERIMENTAL
A shale core plug and a sandstone core plug were chosen for the study. The characteristic
information on each rock studied is shown in Table 1. Each core sample was confined
hydrostatically by fluorinert to a pressure of 2500 psi in an Oxford Instruments P5
overburden NMR probe [2] in an Oxford Instruments GeoSpec 2-75 rock core analyzer
[3]. The samples were evacuated with a vacuum pump, then as received or dry T2
measurements were taken before the introduction of methane. Methane was then
introduced to the samples at 2000 psi. T2 measurements were acquired at 2 minute intervals
for the first hour, then at 15 minute intervals for the following 3 hours, then at 60 minute
intervals for the remainder of the experiment in the sandstone and the shale. These T2
measurements were employed to retrieve the total gas content present in each rock as a
function of time. T1-T2 maps were also acquired with and without methane for the shale.
Acquisition parameters for the T2 measurements and T1-T2 maps are shown in Table 2.
Data acquisition and analysis of the T2 and T1-T2 data was achieved via Green Imaging
Technologies software [4]. Pore volumes were determined using NMR volumes from T2
measurements for both the shale and sandstone. To fully saturate the rocks, the shale was
pressure saturated with brine at 10 000 psi in a pressure cell for three days while, the
sandstone was brine saturated in a vacuum saturation apparatus.
RESULTS
As mentioned above, the gas absorption/adsorption characteristics were studied for a shale
(Eagle Ford 1) and a sandstone (Carbon Tan 1). These rocks were chosen due to the
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expected difference in their gas absorption/adsorption characteristics. The higher surface
to volume ratio of the pores in the shale coupled with its higher organic content should
make the shale much more likely to exhibit adsorption of methane. The presence of organic
content in the shale (as received) was confirmed prior to the methane absorption/adsorption
experiment using T1-T2 NMR maps recorded at different temperatures (Figure 1). Organic
content is visible in the T1-T2 maps as intensity off diagonal at each temperature. The
significant increase in intensity observed in the 70ºC data reflects the organic content
liquefying with temperature and as a result its T1 becoming longer bringing more intensity
into the scale of the map. This increases the observed NMR porosity of the shale.
The first set of gas experiments were to record a series of T2 scans as a function of time for
both the sandstone and the shale. These scans provided the total gas content in each rock
as a function of time. Specifically, the upper panel of Figure 2 shows the volume of
methane (@ 2000 PSI) for both rocks as a function of time. From this data, it is clear that
there is a difference in behaviour for each rock. At first both rocks are very quickly filled
with a volume of methane. For the sandstone, it is filled to approximately its pore volume
via absorption. For the shale, it is filled to 75% of its pore volume via absorption. This
absorption is most likely occurring in the small fractures and larger pores. After this initial
absorption, the sandstone shows no more appreciable increase in volume. Conversely, the
shale shows an increase in gas content over a period of several hours. After approximately
1.5 hours the shale has been filled to its pore volume via absorption. The shale continues
to take on approximately another 35% of a pore volume due to adsorption over a period of
several hours. This yields a final gas content consisting of approximately 65% absorbed
gas and 35% adsorbed gas which is consistent for shales with methane pressure around
2000 PSI [5].
The lower panel of Figure 2 shows the total gas content (adsorbed and absorbed) of both
the shale and the sandstone. In order to retrieve the total gas content, the volume of methane
(scm3) at 2000 PSI (Figure 2 – upper panel) was converted to the volume of methane at
standard temperature and pressure (15ºC and 1 atm) using the ideal gas equation. The
converted volume was then divided by the bulk volume of each rock yielding a total gas
content in units of scm3/cm3. For the shale, a total gas content of approximately 8 scm3/cm3
was observed and this is consistent with other shales [5].
One of the main goals of this work was to see if NMR could be used to distinguish adsorbed
gas from absorbed gas. Figure 3 shows a comparison of two background subtracted T2
spectra taken at different times as the shale was being filled with methane. The peaks in
the spectra represent the different pore networks in the shale. The red spectrum was taken
a few minutes after the introduction of methane into the rock where absorption dominates.
The blue spectrum was taken several hours after the introduction of methane where both
absorption and adsorption are occurring. The increase in observed methane volume when
going from the red trace to the blue trace seems to be occurring in both pore networks
equally. There is no distinction between absorption and adsorption. This is not unexpected
as the adsorbed methane could have a T2 very similar to the absorbed methane in the pores
of this shale. In addition, the adsorbed and absorbed methane are likely in fast exchange
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with one another making distinguishing between them impossible. The ability to
distinguish between adsorbed and absorbed methane may be dependent on the shale being
studied. Other shales may have pore networks where conditions exist where adsorption
could be distinguished from adsorption. Gu et al. have reported seeing differences in T2
spectra due to adsorption vs. adsorption of methane in a shale [6].
Figure 4 shows a T1-T2 map of shale Eagle Ford 1 taken a few hours after the introduction
of methane. If the map in Figure 4 is compared to the map in the left-hand panel of Figure
1 (as received), conclusions about where the methane has gone once it entered the shale
can be drawn. The long tail in the map at T2 values greater than 1 ms corresponds to
methane filling into the large inorganic pores of the shale. Conversely, the increase in
intensity overlapped with the organic content observed (T2 < 1 ms) in the left-hand panel
of Figure 1 corresponds to methane entering the smaller organic pores of the shale. The
methane seems to be filling all the pores equally within a few hours of methane being
introduced into the rock.
CONCLUSION
A method has been presented for using NMR to measure absorption, adsorption and total
gas content in shales. T2 measurements were taken over time after the introduction of
methane to both a sandstone and a shale. Methane absorption was observed in both rocks,
while adsorption was only observed in the shale. T1-T2 maps were also acquired in the
shale. They showed that methane filled both the inorganic pores and organic pores equally.
This agrees with changes in the T2 spectra of the shale. T2 peaks originating from inorganic
and organic pores grow at equal rates after the introduction of methane. No distinction was
made between adsorbed and absorbed methane in the shale. This is likely due to fast
exchange between the absorbed and adsorbed gas. Additionally, the absorbed and adsorbed
gas could have very similar T2 values.
FUTURE WORK
This paper summarizes the preliminary results of our investigation looking into using NMR
to measure gas adsorption and absorption. As the investigation is preliminary, there is still
a significant amount of work to complete. First, we will repeat the experiment on the shale
sample, acquiring T2 measurements at shorter intervals initially to get more data relating
to absorption. We will then run the experiment for a week to determine whether more
methane is adsorbed at later times. We will also acquire T1-T2 maps during this longer
experiment to see if any changes in the maps over time could be used to distinguish
absorption from adsorption. The ultimate goal of the work is to generate a gas isotherm
using NMR, so we will repeat the experiment in the shale at several different pressures to
generate the isotherm. Finally, we will acquire T2 measurements on shales of different
origins to investigate how the isotherms may vary with shale type.
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REFERENCES
1. Alexander, T., Baihly, J., Boyer, C., Clark, B., Waters, G., Jochen, V., Le Calvez, J.,
Lewis R., Miller, C. K., Thaeler, J. and Toelle, B. E., “Shale Gas Revolution,” Oilfield
Review, (2011), 23, 3, 40-55.
2. P5 Overburden Probe User Manual, Version 1, Oxford Instruments, Green Imaging
Technologies.
3. Geo-Spec 2-75 User Manual, Version 1.8, Oxford Instruments.
4. GIT Systems and LithoMetrix User Manual, Revision 1.9, Green Imaging Technologies
5. Lu, X.-C., Li, F.-C., and Watson, A. T., “Adsorption measurements in Devonian shales,”
Fuel, (1995), 74, 4, 599-603.
6. Gu, Z., Liu, W., Sun, W., Hu, Z., “NMR Response of Methane in Gas Shale,”
Unconventional Resources Technology Conference, August 1-3 2016, URTeC 2438441.
Tables and Figures
Core Sample Sandstone (Carbon Tan 1) Shale (Eagle Ford 1)
Origin Utah, USA Eagle Ford, Texas, USA
Core Diameter (cm) 2.51 3.81
Core Length (cm) 5.08 4.79
Bulk Volume (mL) 25.14 54.61
Dry Core Mass (g) 55.54 129.16
Pore Volume (mL) 4.10 2.60
Porosity (p.u.) 16.3 4.76
Table 1. Properties of rock samples.
Measurement T2 T1-T2
Recycle delay (ms) 750 1000
Tau (µs) 50 50
Number of Echoes 5000 5000
Number of Steps N/A 30
Filter Width (kHz) 125 125
90º Pulse Length (µs) 7.5 7.4
180º Pulse Length (µs) 15.2 15.0
Table 2. Acquisition parameters for T2 and T1-T2 measurements of sandstone (Carbon Tan
1) and shale (Eagle Ford-1).
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Figure 1. T1-T2 NMR maps for the as received shale sample (Eagle Ford 1) tested taken
at 30ºC and 70ºC.
Figure 2. Volume of methane and total gas content as a function of time for shale sample
(Eagle Ford 1).
T 2 (ms)
T 1 (
m s )
Eagle Ford-1 30C
10 -2
10 0
10 2
10 4
10 -2
10 -1
10 0
10 1
10 2
10 3
10 4
0
0.02
0.04
0.06
0.08
0.1
0.12
T 2 (ms)
T 1 (
m s )
Eagle Ford-1 70C
10 -2
10 0
10 2
10 4
10 -2
10 -1
10 0
10 1
10 2
10 3
10 4
0
0.02
0.04
0.06
0.08
0.1
0.12
0 1 2 3 4 5 6 7 8 9 10 0
1
2
3
4
5
Time(hours)
V o
l. C
H 4 @
2 0 0 0 P
S I(
c m
3 )
0 1 2 3 4 5 6 7 8 9 10 0
5
10
15
20
25
Time(hours)
G a s C
o n
te n
t (s
c m
3 /c
m 3 )
Sandstone - Carbon Tan-1
Shale - Eagleford-1
Sandstone - Carbon Tan-1
Shale - Eagleford-1
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Figure 3. Background subtracted T2 spectra measured after introduction of methane to shale
sample (Eagle Ford -1).
Figure 4. T1-T2 map recorded several hours after introduction of methane to shale sample
(Eagle Ford -1).
10 -2
10 -1
10 0
10 1
10 2
10 3
10 4
0
0.01
0.02
0.03
0.04
0.05
0.06
0.07
0.08
0.09
T2 Relaxation Time (ms)
V o
lu m
e o
f M
e th
a n
e @
2 0 0 0 P
S I (c
m 3 )
Pore Size Distribution Hours After Methane Fill
Pore Size Distribution Within Minutes of Methane Fill
10 -2
10 -1
10 0
10 1
10 2
10 3
10 4
10 -2
10 -1
10 0
10 1
10 2
10 3
10 4
T 2 (ms)
T 1 (
m s )
Eagle Ford-1 30C 2000 PSI Methane
0
0.005
0.01
0.015
0.02
0.025
0.03
0.035
0.04