multinuclear nmr microscopy of two phase fluid systems in porous rock 1996 magnetic resonance...

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Magnetic Resonance Imaging, Vol. 14, Nos. 718, pp. 869-873, 1996

Copyright 0 1996 Elsevier Sc ience Inc.

Printed in the USA. All rights reserved

0730-725 X/96 15.00 + .OO

ELSEVIER

l Contributed Paper

PI1 SO730-725X( 96) 00218-2

MULTINUCLEAR NMR MICROSCOPY OF TWO-PHASE FLUID

SYSTEMS IN POROUS ROCK

DARYL A. DOUGHTY AND LIVIU TOMUTSA

BDM-Oklahoma, National Institute for Petroleum and Energy Research (NIPER), Bartlesville, OK, 74005, USA

The high-field magnetic resonance (MR) characteristics of fluids in porous reservoir rock exhib it short

T2

relaxation times and broad natural line widths. Thesecharacteristics severely restrict which MR imaging

(MRI) methodology can be used to obtain high-resolution porescale magesof fluids in porous rock. An

MR microscopy protocol based on 3D backprojection using strong imaging gradients was developed to

overcome many of theseconstraints. To improve the imagequality of two-phasesystems,multinuclear MRI

using proton MR to image he brine phaseand ‘q MR of a fluorinated hydrocarbon to image the oil phase

was used. Resolution as high as 25 microns per pixel has been obtained for fluid systems n Bentheim and

Fontainebleau sandstones.Separate proton and ‘ ’ imagesof brine and oil phasesshow good agreement

with total saturation images.Software has been developed to perform 3D erosion/dilations and to extract

the pore size distribution from binarized 3D imagesof fluid filled porosity. Results rom pore size measure-

ments show significant differences in the nature of the pore network in Fontainebleau and Bentheim

sandstones.

Copyright 0 1996 Elsevier Science Inc.

Keywords:

Two-phase luid systems;Porous rock; NMR microscopy.

INTRODUCTION

In petroleum reservoir assessment and characteriza-

tion, MRI is a valuable nondestructive imaging tech-

nology used to image fluids within cores,’ providing

information about porosity distribution and how it is

affected by rock heterogeneity. MR microscopy pro-

vides information about the pore network connectivity,

which is directly related to fluid f low characteristics

within the rock matrix, pore sizes, and fluid distribu-

tions in pores.2 The high resolution achievable allows

visualization of the effect of rock/fluid interactions on

oil and water distributions within the pore spaces of

reservoir rocks. Such a capability aids in understanding

oil displacement processes taking place at the pore

level, which are essential in understanding the mecha-

nisms of various oil recovery processes. High-resolu-

tion MR microscopy wa s recently expanded to include

multinuclear imaging for direct imaging of separate

phases using fluids th.at are tagged by an MR-active

marker such as 19F.

EXPERIMENTAL

The most efficient 3D imaging process for fluids in

porous rock is the 3D projection reconstruction se-

quence.3 The imaging gradient is of fixed amplitude

and its direction in space is controlled by three X-, Y-,

and Z-components. Because the gradient is switched

on prior to the RF pulses in the spin echo and remains

on until the signal is acquired, rapid switching of the

gradient is not required and the time to echo (TE) can

be shorter, maximizing signal strength for fluid/rock

systems, which have a short

T2

relaxation time. How-

ever, achieving high resolutions using this protocol

requires strong gradients and high RF bandwidths. The

algorithm used to process the projection reconstruction

image data is a two-stage implementation of the convo-

lution method for parallel beam reconstruction tomog-

raphy from the Donner Laboratory algorithms.4 In

adapting this algorithm for MR imaging, the MR pro-

jection is treated like a parallel beam emission projec-

tion of source intensity across the dimension of the

object defined by the gradient direction. The result is

Address correspondence to D.A. Doughty, BDM-OkIa- (NIPER), P.O. Box 2565, Bartlesville, OK 74005.

homa, National Institute for Petroleum and Energy Research

869



870

Magnetic Resonance Imaging 0 Volume 14. Numbers 7/S, 1996

a 3D Cartesian image of the fluid-filled porosity of the

sample, where pixel intensity is expressed as

a

O-255

level, &bit value.

The small core plugs of reservoir rock used for MR

microscopy are typically about 5 mm in diameter and

7- 10 mm long. They are mounted inside a core holder

made from two Teflon end caps and two layers of

Teflon shrink tubing. The inner layer is an FEP-type

Teflon, which shrinks at 206”C, and the outer layer

is PTFE Teflon, which shrinks at 320°C. This higher

temperature softens the inner layer, bonding the end

caps and core plug into a leak-proof assembly. Small

diameter Teflon tubing is clamped into the end caps

and permits the exchange of fluid components in the

core plug while mounted in the spectrometer. Typical

imaging parameters are: 200 KHz projection band-

width, 60 gauss/cm gradient, 256

X

128 gradient ori-

entations, 256 complex points per projection, 4-8

summed accumulations per projection, 1.28 ms TE,

and 0.4 s PD for proton imaging of brine. A longer

PD is used for imaging the oil phase. The brine used

is 0.5 NaCl by weight with 0.023 MnC12 added as

a T1 relaxation agent. The oil phase is usually Soltrol

or a fluorinated compound such as hexafluorobenzene

(HFB) or 3,5-bis (trifluoromethyl) bromobenzene

(TFMBB ) .

RESULTS

Figure 1 shows the two-phase brine/Soltrol fluid

filled porosity for three successive regions down the

axis of a core plug of Fontainebleau sandstone for

brine and Soltrol/residual brine conditions. The resid-

ual brine condition was established by flowing Soltrol

through the brine saturated core plug until no addi-

tional brine was produced at the outlet. The image is

displayed as a surface-rendered view of porosity at a

voxel intensity matching the brine saturated porosity.

Image resolution was about 30 microns per voxel edge.

The first column (A, D, and G) shows the initial brine-

saturated total porosity. The direction of fluid f low in

the figure w as from (A) to (D) to (G) back to front.

The second column (B, E, and H) shows the corre-

sponding oil occupied porosity obtained using a longer

TE to suppress the brine signal for the same respective

regions. The last column (C, F, and I) shows the corre-

sponding residual brine occupied porosity in the three

regions obtained by difference. Even though at least

10 pore volumes of oil were flowed through the core

plug before the second experiment was run, Fig. 1

shows that the relative volume of the total porosity

occupied by Soltrol is decreasing and the volume occu-

pied by brine is increasing as the distance from the inlet

port increases, which is a typical end effect noticed in

fluid flow in core plugs.

Using a

longer TE to suppress the more quickly

relaxing brine phase is a common approach to sepa-

rately imaging two-phase fluid systems. However. at-

tenuation of the projection areas at certain gradient

orientations wa s noticed in these experiments com-

pared to the projections for short TE experiments. Fig-

ure 2 shows the results of an experiment on a small

spherical, water-fil led phantom at a TE of 10.24 ms

for varying gradients strengths. Off-axis gradients in-

volving combinations of the Z-gradient with either X-

or Y-gradients were discovered to cause a suppression

of projection signal strength, increasing with TE and

gradient strength. In Fig. 2, the area under the MR

projection signal, normalized to the area for a TE of

1.28 ms, was plotted vs. the gradient angle index in

the XZ plane (0- 180”). The figure shows that the

average signal area for all gradient orientations is

strongly affected by gradient strength with the stronger

gradient causing a greater suppression of the signal at

a given TE. Also, the influence of gradient orientation

on the signal is much more pronounced for the stronger

gradients. The average suppression of the MR signal

BRINE OIL at

RESIDUAL BRINE

RESIDUAL BRINE

I I

800 microns

Fig. 1. Surface-rendered D views of fluid-saturatedFon-

tainebleau andstone. he first column A, D, and G) shows

the brine-saturatedock. The second olumn (B, E, and H)

shows he oil phase t residualbrine obtainedusinga longer

TE to suppresshe brine signal.The last column C, F, and

I) shows he residualbrine by difference.



Multinuclear NMR microscopy of two-phase fluid systems

D.A. DOUGHTY AND L. TOM UTSA 871

80

,

20

0

20 40 60 80 100 120

Angie index

Fig. 2. The areaunder the MRI projection at a TE of 10.24

ms s plotted as a function of XZ-gradient angle ndex (O-

180degrees) or severalgradientstrengthsn gauss/cm.A

markedgradientorientationeffect is evident for the stronger

gradients.

in the presenceof a gradient is causedby the diffusion

of fluid molecules from one location in the sample to

a region of different magnetic field during the TE.

This causes he contribution from that molecule to be

missing from the echo signal. An explanation for why

this effect should be influenced by gradient orientation

is not available at this; time. Using multinuclear MRI

with separate requencies to image the two phaseswith

similar short TEs was chosen to eliminate the impact

of this effect.

Another image effect in a high-resolution MR image

of a fluid-filled porous medium is the variation in voxel

brightness across the different pores or from pore to

pore in the images. One such interpretation is that the

dimmer voxels represent places within the rock/fluid

system where only a part of the voxel is occupied by

fluid-filled porosity contributing to the signal. Figure

3 shows an enlarged view of part of one cross-sectional

slice of a brine saturated phantom’s image showing a

brine-filled wedge formed by putting a small Teflon

spacer, 0.250 mm thidk, between small squaresof glass

plate and filling the void with brine. The white triangle

shows the actual shape of the wedge, and the arrow

points to the region where the thickness of the wedge

became equal to the voxel dimension (38 microns in

this image). Even in this region the brightness of the

Fig. 3. Part of a cross-sectionallice rom the 3D MR image

of a brine filled, wedge-shaped hantom.The brine is the

lighter shades isplayedusinga O-255 grey scale.The white

triangle shows he shape f the wedge.The arrow points o

where the wedge s one voxel thick (38 microns).

voxel is less than that in wider regions of the wedge.

Another artifact of the reconstruction process is that

the edges of objects are blurred over a width of about

two voxels, as shown in Fig. 3. At the spot where the

wedge is one voxel wide, the image spreadsover three

or four voxels causing a reduced intensity. The inten-

sity falls off even more as the thickness of the wedge

falls below one voxel. This variation in intensity could

be used to make a quantitative estimate of fractional

t

I

800 microns

Fig. 4. Slice views of fluid-saturatedBentheim sandstone.

The sl ices are 64

x

64 voxels extracted from near the center

of 3D multinuclear MR images. (A) Brine (‘H); (B)

TFMBB at residual brine ( 19F); (C) Brine at residual

TFMBB (‘H); (D) Residual TFMBB ( 19F). Fluid-fil led

pores are the lighter shades displayed using a O-255 grey



872 Magnetic Resonance Imaging 0 Volume 14, Numbers 7/8, 1996

t I

800microns

Fig. 5. Two brine-saturated andstoneshowingdifferences

in pore structure.The lighter areasare the brine-filled pore

spaces isplayedusing a O-255 grey scale. A) Bentheim

sandstonehowinga well-connected ore system. B) Binar-

ized imageof A. (C) Fontainebleau andstone howing so-

lated argerporeswith numerous mallpores. D) Binarized

imageof C.

voxel filling in different regions of MR images and

effectively increase resolution.

Figure 4 shows the results of a multinuclear MR

microscopy experiment on a core plug of Bentheim

sandstoneusing brine and TFMBB. The same maging

gradient strengths were used for both the proton and

“F images. Square 2D slices 64 x 64 voxels on each

side and extracted from near the center of the 3D im-

agesare shown. Figure 4A shows the proton image of

the brine saturated core plug. Figure 5B shows the oil

phaseusing “F MRI. Figure 4C shows he brine image

at residual oil, and Fig. 4D shows the residual oil,

again imaged using “F MR. In the images the voxel

intensity is displayed using a O-255 level gray scale.

The “F images had to be scaled by the ratio of the

‘H/“F MR frequencies to obtain the same size and

resolution. If the images in 4C and 4D were added,

which would represent the total fluid-filled porosity

in the core plug, good agreement with 4A would be

obtained. This lends confidence to using multinuclear

MR imaging to separately image the two phases.

Software was developed at NIPER to track pores

through 3D space and develop information on pore

size and connectivity using an erosion/dilation process

similar to that developed by Ehrlich5 for petrographic

thin-section analysis but extended to three dimensions.

The erosion/dilation process works on binarized im-

ages where voxels at or above a selected ntensity are

set to an intensity value of 255 and those below the

reference intensity are set to zero. A 3D kernel con-

sisting of a 3 x 3 x 3 cross with seven voxels is

scanned progressively through the image volume. As

the kernel encounters filled voxels in the image plane,

in the erosion process the value of the central voxel is

replaced by the minimum value of the kernel voxels.

For a binarized image this is equivalent to being either

on (255 ) or off (0). Erosion is used to break narrow

connections between larger pore spaces. n the dilation

process the value of the central voxel is replaced by

the maximum value of the kernel voxels. Dilation is

used to replace the previously eroded outer layer of

voxels for the larger pore spaces. The software will

permit up to six successivestagesof erosion/dilation.

In the pore size determination used on the binarized

image data, as the layers of the image are scanned, a

pore index is established for each separate activated

voxel encountered during the scan. If the newly en-

countered voxel is determined to be a nondiagonal

neighbor to a previously counted voxel considering all

three dimensions, the voxel count is incremented for

that pore index. If a bridge is later discovered connect-

ing two previously isolated pores, the voxel count for

the highest pore index is added to the lower pore index

and the higher pore index is zeroed and freed for later

use. The end result of the pore size determination is a

._

Erosions/ Dilations

Fig. 6. Pore measurementsn binarized pore images.The

largest pore as a fraction of total porosity remainingafter

erosion/dilation s plotted vs. the numberof erosion/dilation

cycles. The Bentheimand Fontainebleausandstoneshow

markeddifferences n pore structure.



Multinuclear NMR microscopy of two-phase fluid systems D.A.

DOUGHTY AKD

L.

TOMUTSA 873

histogram of pore size: for the image volume and a

table showing the ranges in X, Y, and Z for each pore.

Figure 5 shows 2D MR slices taken from near the

center of 3D images of two brine-saturated pore sys-

tems. Figure 5A shows the image of a core plug of

Bentheim sandstone of 24 porosity. The same gray

scale of voxel intensity was used for this figure. The

binarized version of the same image is shown in 5B.

Figure 5C shows a similar image of a core plug of

Fontainebleau sandstone of 12 porosity. Figure 5D

shows the binarized version of this image. The images

show a considerable variation in appearance. The Fon-

tainebleau image shows much greater variation in

voxel intensity and pore size with isolated large pores

separated by low porosity areas of much smaller pores.

The Bentheim image shows a higher image uniformity

with more connectivity between neighboring pores. No

erosion/dilation was done in obtaining the images in

Fig. 5.

Figure 6 shows results of pore size/connectivity

analysis on the two systems, where the largest pore in

the histogram, expressled as a fraction of the total po-

rosity remaining at each stage, is plotted vs. the number

of successive erosion/dilation stages for the two sand-

stone binarized images. For the Bentheim sandstone,

even after one stage of erosion/dilation, most of the

porosity is contained

in

one large pore throughout the

image pore space. The largest pore size then falls o ff

sharply after an additional erosion/dilation and then

starts to increase. In contrast to the Bentheim system,

the results for the Fontainebleau sandstone show an

opposite trend with the largest pore size

starting

off

small and then increasing modestly after several ero-

sion/dilation stages. After two stages of erosion/dila-

tion the Fontainebleau system behaves similarly to the

Bentheim result. These statistical results confirm the

visual differences noted above and indicate the high

connectivity in the Bentheim core plug compared to

the Fontainebleau sample.

CONCLUSIONS

A technique of MR microscopy that has success-

fully imaged fluids at pore scale in sandstones has been

developed at NIPER using the projection reconstruc-

tion pulse sequence on small core plugs with strong

imaging gradients. Voxel resolutions as high as 25

microns have been achieved.

Multinuclear MR imaging of two-phase fluid sys-

tems using 19F substituted hydrocarbons permits ob-

taining unambiguous

mages of the separate water and

oil phases leading to better understanding of fluid dis-

tributions in porous rock.

Software has been developed at NIPER which can

perform a true 3D erosion/dilation process on the bi-

narized, pore scale, MR images, and then obtain pore

size measurements and track pore connectivity.

Results from pore size measurements show signifi-

cant differences in the nature of the pore network in

Fontainebleau and Bentheim sandstones.

1.

2.

3.

4.

5.

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gineers,Houston,TX; October 2-5, 1988.

Doughty, D.A.; Tomutsa,L.; Madden, M.P. Pore scale

fluid imaging n reservoir ock by NMR microscopy;ACS

National Spring Meeting Symposiumon Applications of

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Denver, CO; March 28-April 2, 1993.

Doughty, D.A.; Tomutsa,L. NMR microscopy or fluid

imagingat pore scale n reservoir rock. Joint Society of

CoreAnalysts/Society of ProfessionalWell Log Analysts

Symposium, Oklahoma City, OK; June 14-17, 1992.

Huesman,R.H.; Gullberg. G.T.; Greenberg,W.L.; Bud-

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gorithms or Reconstruction omography,Berkeley, CA.

LawrenceBerkeley Laboratory, University of California;

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Ehrlich, R.; Crabtree,S.J.; Kennedy, S.K.; Cannon,R.L.

Petrographic mageanalysis . Analysis of reservoirpore

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