12d

left-handed (b) right-handed 

8c

A

C

solvent

solvent

Si

Si s porou

-8

-7

-6

-5

-4

-3

-2

-1

0

0.0

∆H 6 30

)

Neutron reflectivit

y, log10

R

B

0.25 0.20 0.15 0.10 0.05

6

5

4

3

2

1

0

60 40 20 0

i S m fro e distanc

(Å) e surfac

Si

porous

Si

solvent

-0.5

4.0

6.5

Q, r Momentum transfe

z ) -1 (Å

solvent nSLD

ρn

 (10-6 ) -2 ÅnSLD, 

ρn (10-6 Å-2)

solvent

Co (d) 7

Zn 6 Mn 7

Mn Zn

Zn

Mn

 Co8

Zn 3 Mn 9

5

9

13

17

21

25

6 5 4 3 2 1 0

0

1

2

3

4

20

15

10

5

0

0

ρ nSLD solvent 2, n

2

 (10-6 ) -2 Å

nSLD solvent 1, 

ρ

n

1 (10

Information gain, 

Δ

24 20 16 12 8 4

 (h) t Counting time, 

GEOLOGY

34 NIST CENTER FOR NEUTRON RESEARCH

Solvent-pore interactions in Eagle Ford 

shale by ultra and small-angle neutron scattering

J. McFarlane,1 L. M. Anovitz,1 V. H. DiStefano,1,2 A. G. Stack,1 E. Perfect,3 D. F. R. Mildner,4

M. Bleuel,4 S. J. Chipera,5 K. C. Littrell,1 M. C. Cheshire,1 and K. E. Manz2

1 Oak Ridge National Laboratory, Oak Ridge, TN 37830

2 Bredesen Center, University of Tennessee, Knoxville, TN 37996

3 Department of Earth and Planetary Science, University of Tennessee, Knoxville, TN 37996

4 NIST Center for Neutron Research, National Institute of Standards and Technology, Gaithersburg, MD 20899

5 Chesapeake Energy, Oklahoma City, OK 73154

T

he interaction of fluids with porous materials is of interest 

for many applications including extraction of hydrocarbons 

from shales. In the field, shale fracturing can be done 

with pressurized water, hydrocarbons, or gases, depending 

on the depth and mineralogy of the formation. Although the 

technology is mature, the process is not well understood, 

leading to inefficiencies in fluid usage during fracturing and 

decreases in hydrocarbon production over time. In this study, 

we examined the effect of organic solvents and acidic aqueous 

solutions on rock porosity using small and ultra-small angle 

neutron scattering (U)SANS. The extracted material was 

analyzed by gas chromatography-mass spectrometry (GCMS) to determine if there is a correlation between the type 

of organic extracted, shale maturity, and how the extraction 

process affected porosity.

Chesapeake Energy Corporation provided six cores taken 

from the Eagle Ford Shale formation as shown in Figure 1 

[1]. Five slices from each, cut perpendicularly to bedding to 

minimize variation, were soaked for ≈ 2 weeks in one of five 

solvents: toluene, cyclohexane, methanol, dichloromethane, 

or 0.01 mol/L HCl (pH = 2). Total ion chromatograms from 

GC-MS were used to quantify and compare the amount of 

organic matter extracted from each sample. Chromatograms 

of specific ion masses were used to identify classes of 

chemical compounds: linear alkanes by the mass/charge 

m/z = 57 for C4H9

+ and aromatic compounds by m/z = 77 for 

C6H5

+. Most of the hydrocarbons extracted were n-alkanes, 

(nC11 to nC31), although significant amounts of branched 

alkanes and aromatics were observed. The molecular weight 

distribution of the extracted hydrocarbons changed with 

the solvent. Methanol mostly dissolved light alkanes and 

extracted the smallest overall amount of hydrocarbon because 

it has the lowest compatibility with the organic matter. The 

other organic solvents—dichloromethane, toluene, and 

cyclohexane—all extracted similar amounts of organic matter, 

although toluene and cyclohexane extracted more aromatics 

and dichloromethane extracted more branched alkanes. The 

only aqueous solvent tested, HCl, surprisingly extracted the 

longest alkane chains, possibly because physical dissolution 

of carbonate minerals liberated heavier organics. Lighter 

hydrocarbons were not extracted with HCl, suggesting the acid 

could not penetrate the hydrophobic bitumen and kerogen. 

Overall, the amount of extracted material correlated with the 

amount of total organic carbon present.

The porosity of the shale samples in the 1 nm to 20 μm range 

was analyzed by (U)SANS. Porosity was determined assuming 

a two-phase system and that scattering primarily occurs at 

the pore/mineral interface [2]. Because neutron scattering 

length density (SLD) of organic matter declines with decreasing 

carbon-to-hydrogen ratios, empty pores and pores filled with 

alkanes contribute similarly to scattering [3]. More complex 

organic matter has increasingly larger SLDs, behaving more like 

the rock matrix. Hence, the apparent porosity determined by 

(U)SANS includes pores filled with alkanes and aromatics. It is 

clear from Figure 2 that most of the change in porosity, as well 

as the reduction in asymmetry, occurs at low maturities – in this 

case between about 0.56 and 0.77 – although the reduction 

in asymmetry is much less in clay-rich than in carbonate-rich 

samples. At higher maturities there is little observable trend in 

porosity with maturity [4].

The mineral composition of the shale plays an important role 

in the total porosity. We found a positive correlation between 

the total porosity and the percentage of clay, pyrite, and total 

organic carbon. The distribution of pore sizes was bimodal in all 

samples in the range examined, which is typical for shale. The 

number distribution of smaller diameter pores (maximum 3 nm 

to 7 nm) corresponds to the percentage of clays, in agreement 

with the literature [5]. There were far fewer larger pores but, 

volumetrically, they contribute a large fraction of the total porosity.

Significant changes were observed in the cumulative porosities 

of the shale samples after solvent contact. Total cumulative 

porosity decreased with extraction across all solvents for clayrich samples (Figure 3), with the greatest decrease attributed to 

dichloromethane. Organic extraction in carbonate-rich samples 

increased total porosity in some samples and decreased it in 

others. A positive correlation between the amount of organic 

matter extracted and the initial sample porosity may indicate 

that initial pore accessibility can affect hydrocarbon extraction.
solvent

Si

solvent

solvent

Si

Si

left-handed

solvent

solvent

Si

Si

29

∆H

iiNIST CENTER FOR NEUTRON RESEARCH FOREWORD a

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Foreword

GEOLOGY

2019 ACCOMPLISHMENTS AND OPPORTUNITIES 35

Solvent-pore interactions (solvent-clay or solvent-kerogen) 

were considered to see if they could explain the significant 

changes, primarily decreases, in porosity after extraction. 

The pore structure may be affected by a number of chemical 

and physical solvent/matrix interactions, including reactions 

between the clay mineral interfaces, trapped hydrocarbons, 

and solvents [6]. Smectite layers in clay minerals can expand by 

exchange of interlayer cations due to intercalation of water or 

other fluids [7]. Acids like HCl can provide a hydrogen ion for 

that exchange. To a lesser extent, organic solvents have also 

been demonstrated to expand clay layers [6]. However, by this 

mechanism HCl should have caused the greatest decrease in 

porosity from water intercalation and cation exchange and this 

was not observed, so a different mechanism caused the pore 

volume decrease.

Kerogen swelling may also have caused some of the pore 

volume changes. Kerogen is a complex polymeric material 

based on a lattice of polyaromatic hydrocarbons. It can swell 

extensively when immersed in organic solvents. Hence, the 

measured change in porosity from the solvent contact was 

compared to its solubility parameter. The largest effect was 

observed at 20 MPa0.5, which is close to a previously reported 

solubility parameter of kerogen (19.43 MPa0.5) [8]. This 

suggests that kerogen swelling was the likely cause of the 

porosity decrease. The decrease in porosity in the samples 

contacted with HCl was not adequately explained by either 

clay-layer expansion or kerogen swelling, but kerogen swelling 

may have been offset by carbonate dissolution.

This study had the goal of investigating changes in porosity 

as a consequence of the extraction of organic matter from 

shale minerals using organic and acidic solvents. (U)SANS 

measurements showed that mineralogy, rather than maturity, 

controlled the measured total porosity in these Eagle Ford 

shales. Porosity distributions and total porosity in extracted 

shale samples were compared to samples from the same 

formations that had not been contacted with fluids. There was 

a positive correlation between initial porosity and the extraction 

of alkanes and aromatics, likely arising from the number and 

type of pores in the shale samples. A decrease in porosity with 

extraction is thought to have primarily arisen from kerogen 

swelling upon exposure to organic solvent(s). The extraction 

of hydrocarbons with exposure to HCl probably arose from 

the dissolution of carbonate minerals in the acid. These results 

contribute to our understanding of the fluid-rock interactions 

affecting the efficiency of oil and gas extraction.

References

[1] V. H. DiStefano, et al., Fuel 238, 298 (2018).

[2] A. P. Radliński, Rev. Mineral. Geochem., Neutron 

Scattering in Earth Sciences, 363–397, (2006). 

[3] A. Radlinski, A. Hinde, Neutron News, 13(2), (2002). 

[4] L. M. Anovitz, et al., Interpretation, 5(3), SU59-SU70 

(2015).

[5] U. Kuila, et al., Fuel, 135, 359 (2014). 

[6] M. Kowalska, H. Guler, D. L. Cocke, Sci. Total Environ. 

141, 223 (1994).

[7] S. Aldridge, A. J. Downs, The group 13 metals aluminum, 

gallium, indium and thallium: Chemical patterns and 

peculiarities. John Wiley & Sons, (2011).

[8] L. Ballice, Fuel, 82(11), 1317 (2003).

FIGURE 1: Collection sites for sample cores. (The underlying map was taken 

from the Energy Information Administration, www.eia.gov/maps/maps.htm, 

9-30-2011.)

FIGURE 2: Porosity as a function of maturity, determined for carbonate- and 

clay-rich samples, with Y-orientation parallel to bedding, and Z-orientation 

perpendicular to bedding.

Carbonate-rich samples Clay-rich samples

Porosity (%)Porosity (%)

0

10

20

30

40

50

0

10

20

30

40

50

Maturity (Ro) Maturity (Ro) 0.5 0.7 0.9 1.1 1.3 1.5 1.7 0.5 0.7 0.9 1.1 1.3 1.5 1.7

CARB

LM

CARB 2

CARB 3 CARB 5

CARB HM

CARB 4

CLAY

LM

CLAY 2 CLAY 5

CLAY

HM

Z-orientation

(Anovitz 2015)

Y-orientation

(DiStefano 2016)

CARB LM, CARB HM

CARB 2 - CARB 5

(Anovitz 2015)

Z-orientation

(Anovitz 2015)

Y-orientation

(DiStefano 2016)

CLAY LM, CLAY HM

CLAY 2 - CLAY 5

(Anovitz 2015)

FIGURE 3: Effect of extraction of hydrocarbons on total porosity. Change in total porosity (%)

Toluene

Cyclohexanes

Methanol

Dichloromethane

Hydrochloric acid

CARB 2 CARB 3 CARB 4 CARB 5 CLAY 2 CLAY 5

0

2

-2

-4

-6

-8