Understanding changes in porosity as a function ofoverburden pressure in shales

Application Note 5

For the profitable development of shale reservoirs, it is critical to understand the natural
fractures in the rock and how they may or may not interact with hydraulic fracturing. Whenperforming core analysis, it is also important to assess whether the measured properties havebeen altered by fractures induced during coring.
A key indication of the quantity of the fractures can beobtained by measuring the amount of porosity contained in
the fracture network. In shale formations there usually existsat least two distinct pore networks - one associated with
the intergranular pore network and one associated with thepores within the organic rich kerogen. The fracture network,
either natural or induced, could be thought of as a third pore
network which at ambient pressure would be the largest
in size. The T2 distribution is still able to distinguish thedifferent pore networks because the organic pores are muchsmaller than their non-organic counterparts. In addition, theT2 distributions of the three pore networks should change
differently as a function of confining pressure allowing
further distinction of the three pore networks to be made.
In this application note, we describe techniques using NMR
that can not only obtain the total porosity of shale samples
but can also quantify the amount of porosity arising from thefractures. NMR measurements of the T2 relaxation time were
performed at different confining pressures to quantify theporosity loss as confining stress increases.

MethodThe total porosity and T2 distribution as a function of confiningpressure of four shale core samples was investigated using
NMR. Each dry shale sample was saturated with brine viapressure saturation at 10,000 psi using a Phoenix Instrumentspressure vessel. Following this saturation procedure, eachshale sample was confined hydrostatically by fluorinert in anOxford Instruments P5 overburden NMR probe. Once thepressure was stabilized, the cell was inserted into an Oxford
Instruments GeoSpec 2/53 rock core analyzer. The porosityof each shale core sample was then tested as a function ofconfining pressure at 0, 1000, 2000, 3000, 4000 and 5000 psi.
A T2 NMR acquisition scan of each sample, at each pressure,was used to measure the T2 pore distribution as a functionof confining pressure. The T2 distribution of a fluid saturated
rock is proportional to its pore size distribution. Fluid in smaller
pores has a shorter T2 value while fluid in larger pores has alonger T2 value. The pore volume at each confining pressure
was determined by summing the area under the T2 distribution
curve. The NMR instrument had been calibrated with a sample
of known volume so the NMR signal amplitude indicatedthe volume of fluid within the shale samples. Acquisition
and analysis of the T2 data was achieved via Green Imaging
Technologies’ software.

Understanding changes in porosity as a function of overburden pressure in shales

Results
The pore-size distribution foreach shale core sample tested
at 5,000 psi of confiningpressure can be seen in Figure
1. Shales 1 and 3 have a single
sized pore network while
shales 2 and 4 have threepore networks (labeled: micro,meso and macro) of varying
size. For shale samples 2 and4, the cumulative porosity ofeach network was estimatedby summing the incremental
porosity in certain T2 ranges
corresponding to the different
pore networks.

Figure 1: Pore distribution for shale samples tested at 5000 psi confining pressure

The left panel of Figure 2
shows the porosity of eachpore network of shale 2plotted as a function ofconfining pressure. Thisplot shows that the micro
pore network makes up the
majority of the total porosityof shale 2 (~2.5 p.u.) while
the macro porosity (~0.5p.u.) accounts for the least
portion of the total porosityof shale 2. The center
panel of Figure 2 shows theporosity normalized to 0 psi
and plotted as a function ofpressure.

Figure 2: The porosity of the pore networks of shale 2 as a function of pressureApplication Note 5

From this plot it is immediately obvious that each pore network behavesdifferently with confining pressure. The micro pore network (blue line) shows nocompression with confining pressure. The meso pore network (green line) shows
an approximately linear compression with confining pressure. The macro pore
network shows a sharp decrease in porosity from 0 to 1,000 psi and then no further
compression from 1,000 to 5,000 psi. This is consistent with the observations ofChhatre et al. [1]. In their study, there was a significant decrease in permeability withincreasing stress, suggesting that the largest pores compacted the most.

Finally, the right panel of Figure 2
shows the cumulative porosity ofshale 2 as a function of confiningpressure. Again it is obvious thatthe micro pores contribute to themajority of the total porosity of shale
2 while the macro pores contribute
Figure 3: The porosity of thepore networks of shale 4 as afunction of pressure

the least. Figure 3 shows theporosity data for shale 4 analyzed
in the same fashion as the data forshale 2.

Understanding changes in porosity as a function ofoverburden pressure in shales

Application Note 5Conclusion

Oxford Instruments Magnetic Resonance

A method has been presented for using NMR T2 relaxation

For more information: magres@oxinst.com

times to identify pore networks in shales and their

www.nmr.oxinst.com

dependence on stress. Four samples were tested, all takenfrom wells in potential hydrocarbon-bearing formations.
Two samples had a complex (trimodal) pore size distribution,and two contained only very small pores.

UKTubney Woods, Abingdon, Oxfordshire, OX13 5QX, UK
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Green Imaging Technologies
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Where a complex distribution was present, the stressdependence varied by pore size. The largest (macro) porescompressed significantly at relatively low stress (1,000 psi), andCanadavery little thereafter. This behavior is likely due to the closure of520 Brookside Drive, Suite B, Fredericton, NB, E3A 8V2,

natural or induced fractures. The smallest (micro) pores show

Canadano significant change with stress. This is interpreted to indicate

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that these pores are not part of the mechanical fabric of theTel: +1 506 458 9992 Fax: +1 506 458 9615

rock. The intermediate size (meso) pores show a continuing
compression across the range of stresses.

References[1] Chhatre. S.S., Braun, E.M.,
Sinha, S., Determan, M.D.,
Passey, M.D., Zirkle, T.E., Wood,A.C., Boros, J.A., Berry, D.W.,
Leonardi, S.A. and Kudva, R.A.,
Steady State Stress Dependent
Permeability Measurements
Of Tight Oil Bearing Rocks,
2014 Annual Symposium Of
The Society Of Core Analysts(SCA2014- 012).

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