Using T2 distributions to measure gas isotherms in shales

Application Note 6More than 60% of the United States natural gas production is now attributed to shale reservoirs[1]. This proportion is only expected to grow as more shale reservoirs are discovered andunlocked. The total natural gas content in a shale consists of both absorbed gas in the porous
spaces of the shales and adsorbed gas on the surface of the shale matrix. Adsorbed gas cancontribute a significant fraction (~50%) of the total gas in place in a shale reservoir.
The total gas in place is dependent on the pore pressure
and temperature and is vital to the profitable developmentof a shale reservoir [2]. Gas companies use gas isotherms,
which are a measure of total gas content as a functionof pore pressure, to assess a reservoir’s profitability.
Traditionally, gas isotherms are measured by exposing thecore to helium and methane at ever increasing pressure
while tracking the volume of gas absorbed and adsorbed.
These experiments involve destruction of the core andprovide no information on the pore size distribution.

MethodA shale core plug was confined hydrostatically by fluorinert
to a pressure of 2500 psi in an Oxford Instruments P5
overburden NMR probe [3] in an Oxford Instruments
GeoSpec 2-75 rock core analyzer [4]. The sample
was evacuated with a vacuum pump and then dry T2
measurements were taken. Methane was then introduced tothe sample at 500 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 until

In this application note, we present a method fora total experimental time of 24 hours. The experiment wasmeasuring gas isotherms in shales using NMR.

then repeated with methane pressures of 1000, 1500 and

Measurements of the T2 relaxation time were taken for 24

2000 psi. The T2 measurements were employed to retrieve

hours after the introduction of methane to a shale. Thesethe total gas content present in each rock as a function

measurements were then used to determine the total gasof time. Data acquisition and analysis of the T2 data wascontent and pore size distributions within the rock. This

achieved via Green Imaging Technologies software [5]. TheNMR gas isotherm analysis proves to be advantageous overpore volume of the shale was determined using the NMR

conventional techniques as it can be completed without

volume from a T2 measurement of the fully saturated shale.

destruction of the shale core while also providing pore size

The shale was saturated after being submerged in brine atdistributions.

10,000 psi in a pressure cell for three days.

Using T2 distributions to measure gas isotherms in shales

Results
The volume of gas detected at each pressure was derived for every T2 measurement acquired during the 24-hour test periodusing the area under the curve of each T2 distribution. The volume of gas detected was then converted to total gas content
using the hydrogen index of methane, the bulk volume of the rock, the experimental temperature and pressure, as well as astandard temperature of 292 K and pressure of 1 atmosphere.

The total gas content of the shale for each pressure as a function of timeis shown in Figure 1. This figure shows that it takes two to four hours forthe methane to fully infiltrate the shale core plug. Following this initialstabilization, the gas content is constant over the remainder of theexperiment. Other experiments, with other types of rocks, haveshown that this stabilization period is rock dependent.

Figure 1: Total gas content of methane at 500,1000, 1500 and 2000 psi.

Application Note 6

To generate the total gas isotherm, the average total gas
content was determined for the shale at 500, 1000, 1500 and2000 psi. The average was taken from four hours onwards,
after the methane content in the rock had stabilized. The
resulting total gas isotherm is plotted in Figure 2 (blue trace).
The isotherm has the expected curved appearance as a functionof pressure, a result of the competing mechanisms of adsorption
and absorption.

Figure 2: Total gas, adsorbed gas, and absorbed gas
isotherms of methane in a shale.

To fully characterize the shale gas reservoir, the total gas content should be separated into its contributions from thesecompeting mechanisms. To do this, the absorbed gas isotherm (Figure 2 – green trace) was calculated using the Van der
Waals equation and the pore volume of the rock. The adsorbed gas isotherm (Figure 2 – red trace) was then derived bysubtracting the absorbed gas isotherm from the total gas isotherm.

Using T2 distributions to measure gas isotherms in shales

Application Note 6Conclusion

Oxford Instruments Magnetic Resonance

A method has been presented for measuring gas isotherms inFor more information: magres@oxinst.com

shales using NMR. The method is similar to the conventional

www.nmr.oxinst.com

approach in that methane is introduced to a shale at anumber of pressures. Pore volume is determined using NMR
rather than through the introduction of helium to the sample.
T2 distributions are acquired at each pressure to determine thetotal gas content. The advantages of the NMR method arethat the shale sample is preserved and pore size distributions
are acquired with each T2 measurement, as shown in Figure 3.
Figure 3: Typical gas
pore size distribution

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Canada520 Brookside Drive, Suite B, Fredericton, NB, E3A 8V2,References

Canada[1] U.S. Energy Information Administration, https://www.eia.gov/tools/faqs/
faq.php?id=907&t=8Toll Free: +1 888 944 8462

[2] 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.
[3] P5 Overburden Probe User Manual, Version 1, Oxford Instruments,
Green Imaging Technologies.
[4] Geo-Spec 2-75 User Manual, Version 1.8, Oxford Instruments.

4438[5] GIT Systems and LithoMetrix User Manual, Revision 1.9, Green ImagingTechnologies

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