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Application of NMR T2 to Pore Size Distribution and Movable Fluid Distribution in Tight Sandstones Chaohui Lyu, Zhengfu Ning, Qing Wang, and Mingqiang Chen Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.7b03431 • Publication Date (Web): 16 Jan 2018 Downloaded from http://pubs.acs.org on January 17, 2018
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Energy & Fuels
1 2
Application of NMR T2 to Pore Size Distribution and Movable Fluid Distribution in Tight Sandstones
3
a State Key Laboratory of Petroleum Resources and Prospecting in China University of Petroleum, Beijing, PR China
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b Department of Petroleum Engineering, China University of Petroleum (Beijing), Beijing 102249, PR China
Chaohui Lyu1a,b*, Zhengfu Ninga,b, Qing Wanga,b , Mingqiang Chena,b
5
Abstract: This paper explores the applicability of nuclear magnetic resonance (NMR) technology on pore size distribution
6
(PSD) and movable fluid distribution (MFD) in tight sandstones. Centrifugation experiments and NMR tests are performed
7
on saturated samples. The fluid changes in pores corresponding with three different types of NMR T2 distribution after each
8
centrifugation is then analyzed. In addition, a new method to determine the conversion factor from NMR T2 distribution to
9
PSD is developed. In comparison with the PSD obtained by mercury intrusion porosimetry (MIP), the new method is more
10
suitable for PSD calculation in tight sandstones. Afterwards, the optimum centrifugal force to determine the threshold radius
11
for fluid flow is obtained. Based on this, we analyze MFD in tight formation. Through study, the following results are
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arrived at: Patterns of NMR T2 distributions of outcrop and subsurface cores at water saturation condition can be classified
13
into three types (I, II, III). Among which, type I and type II show a better pore connectivity than type III with NMR T2
14
distribution of a higher movable peak and a lower immovable peak. The optimum centrifugal force for the Chang 6 tight
15
formation to determine movable fluid is 418 psi and pores show no obvious difference with throats when radii are less than
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0.05 µm. Movable fluids are mostly controlled by throats with radii smaller than 1 µm, especially throats with radii between
17
0.3 µm and 1 µm. Movable fluids are mostly stored in pores around the movable peak of bimodal NMR T2 distribution with
18
radii ranging from 10 µm to 100 µm. These pores are residual interparticle pores and dissolution pores. The sets of
19
experiment and the new method presented in this paper are proved effective in quantitively describing PSD and also
20
qualitatively evaluating pore throat connectivity in tight sandstones. Petrophysical characterization by NMR technique
21
provides an effective approach to better understand pore throat structures and storage capacity of tight oil reservoirs.
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Keywords: Tight sandstones; The conversion factor; Nuclear magnetic resonance; Pore throat structure; Movable fluid
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distribution
24
1. Introduction
25
Unconventional resources are playing an increasingly important role in the global energy market, among which tight
26
oil is the most lucrative one.1, 2 However, tight oil reservoir features a wide PSD with massive nanopores, and complex pore
27
throat structures,
1*
3-6
which leads to flow behavior different from conventional reservoirs. Therefore, an accurate and
Corresponding author: Tel.: +86(010)89732318, Email:
[email protected].
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effective pore structure characterization is the basis for successful exploration and development of tight oil reservoirs.
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Current existing pore structure characterization techniques can be classified into three types, including fluid invasion
30
methods, direct imaging methods, and non-invasion methods.7 Fluid invasion methods, such as MIP, rate-controlled
31
porosimetry (RCP) and nitrogen adsorption, have a limited range of measurement of pore size.5, 8, 9 Therefore, some authors
32
combined two or three fluid invasion methods to characterize the overall PSD.5,10-12 However, the different methods differ in
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theoretical principle, inversion algorithm and experimental condition, which cause discrepancies in the overlap range. Direct
34
imaging methods, such as SEM, and scanning transmission X–ray microscopy pore morphology, only provide intuitive
35
microcosmic microscopic images.13, 14 Non-invasion methods, such as X-Ray computer tomography and NMR, provide a
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fast and nondestructive technique for petrophysical characterization. NMR transverse relaxation time (T2) of the saturated
37
cores provides information on PSD, porosity, permeability, and moveable fluid percentage.15-18 In order to obtain pore size
38
distribution from NMR T2, a conversion factor which is represented by C is in need. With the help of C, NMR T2 can be
39
successfully transformed into pore size distribution.17,
40
transformation between PSD and NMR T2. Nowadays, there are many methods to determine C such as the empirical method,
41
the similarity method and the T2cutoff method. C obtained by the empirical method is only applicable to a certain area
42
according to Wang.19 The similarity method determines C through contrasting NMR T2 distribution and the overall PSD
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obtained from other experimental techniques, such as MIP and RCP. C in the Yanchang Formation by this method varies
44
from 0.006 µm/ms to 3.3 µm/ms according to previous publications which reflects a poor applicability.20, 21, 23-25 The T2cutoff
45
method is more applicable to reservoirs with good pore connectivity.26 However, tight sandstones have more pores with a
46
large pore throat ratio, resulting in poor reservoir connectivity.27-29 Hence, a new approach to obtain C is essential for
47
transforming NMR T2 into PSD. In addition, movable fluid percentage is a critical parameter to evaluate formation
48
flowability, which is always obtained by the empirical value of T2cutoff based on NMR tests and centrifugations.21, 23, 26, 30-36
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And predecessors are always focused on sandstone and carbonate in earlier research.35, 36 However, the pores and throats in
21, 22
Therefore, it is an extremely important parameter in the
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tight sandstones are in micro-nano degrees, traditional methods may not be applicable. Therefore, the research of movable
51
fluid percentage for tight sandstones is in great urgency. In this work, more pore throat structure information will be tried to
52
explore from the centrifugation data in view of the Washburn Equation and the conversion factor calculated from the new
53
method, such as the optimum centrifugal force, movable fluid distribution and corresponding throat radii.
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In this paper, mineral compositions are analyzed by X-Ray, pore morphology is observed by SEM, pore throat
55
structures and connectivity are acquired by NMR techniques on centrifuged core plugs being. Three types of pore throat
56
combination are identified by SEM. After each centrifugation, the distribution of movable fluid derived from three NMR T2
57
distribution types are reported and explained. Moreover, a new method for calculating C in tight sandstones is proposed. In
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contrast with the PSD obtained by MIP, this method is more suitable for PSD calculation in tight sandstones. The optimum
59
centrifugal force to apply to the Chang 6 formation is 418 psi. Movable water is mainly stored in pores distributed around
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the movable peak of bimodal T2 distribution with radius ranging from 10 µm to 100 µm, which represents residual
61
interparticle pores and dissolution pores according to SEM results.
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2 Experimental section
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2.1 Samples
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Eleven tight sandstone samples are collected in this paper. Six of which are obtained from the Chang 6 section in the
65
Yanchang Formation, which is currently an important target area for tight oil exploration and development in China.37 Five
66
ones from Yanchang and Shanxi outcrops were collected as referenced samples.
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2.2 Procedures
68
Before our experiments, all core plugs are cleaned and dried at 378.15 K for 24 hours. Porosity and permeability are
69
measured following the Chinese Oil and Gas Industry Standard (SY/T) 5336-1996. Then, every core is cut into three parts
70
for XRD analysis, SEM, and NMR experiments respectively. XRD analysis is conducted by a PANalytical diffractometer to
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acquire the relative mineral percentages, estimated by a semi-quantitative method in XRD analysis. Fresh sections and
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polished samples are coated with gold and then observed by a FEI™ Quanta™ 200F SEM (20KV, High vacuum mode). As
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we focus on NMR experiments in this paper, the parameters and procedures of NMR tests are mainly introduced. The NMR
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measurement parameters are as follow: echo spacing, 0.1 ms; waiting time, 300 ms; echo numbers, 6000; numbers of scans,
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32. All experiments were conducted at room temperature of 293.15K under a relative humidity of 60%. The procedures are
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described as follows. First, dry weight and core size (length, diameter) of the samples are measured. Second, samples are
77
evacuated for 2 hours and then saturated with distilled water under 25 MPa for 48 h. After the saturation, wet weights are
78
measured. The water porosity of each core is calculated by dry weigh, wet weight and its volume. Third, raw NMR data of
79
water-saturated cores are performed after obtaining water porosity. Fourth, five sets of NMR experiments are conducted
80
after each centrifugation (Five centrifugal pressure are set as 21 psi, 84 psi, 208 psi, 418 psi and 696 psi.). The weight of
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each core sample after each centrifugation is measured for moveable fluid analysis. It should be emphasized that keeping
82
core sample static for ten minutes before each NMR measurement aims to ensure the internal fluid balance. As a comparison,
83
the samples for MIP are cut from NMR samples with the lengths of ~2.5 cm. The MIP experiments after six NMR
84
measurements are performed following the standard SY/T 5346-2005 of China.
85
3 Results
86
3.1 Physical parameters of samples
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XRD results (Table 1) show that all samples are rich in feldspar and quartz. Six subsurface samples contain especially a
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lot of feldspar, which is dissolved during diagenesis, resulting in dissolution pores.38 Gas permeability ranges from
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0.0215×10-3 µm2 to 0.23×10-3 µm2, with a mean value of 0.12×10-3 µm2. Helium porosity of our samples is in the range of
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6.46% to 12.36%, with a mean value of 9.78%. The water porosity ranges from 7.79% to 11.97%, with a mean value of
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9.81%. It is worth noting that the initial water saturation of each core exceeds 90% and the highest value (100%) is recorded
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for sample SX-2. A strong water-wet property may explain this.39
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Table 1 XRD results, porosity and permeability of samples Porosity and permeability Sample
L
D
cm
cm
φg
Kg
Type -3
10 µm
2
%
XRD results
φw %
Qz+ Kfs+ Pl
Dol
Ank
TCCM
wt%
Cal wt%
wt%
wt%
wt%
302-31
Reservoir
3.66
2.51
0.264
10.8
9.71
46.5
0.9
-
3.1
28.2
431-15
Reservoir
3.81
2.51
0.086
12.36
11.97
74.2
0.6
-
3.2
22.0
430-10
Reservoir
3.68
2.51
0.024
8.88
7.79
75.5
1.1
-
2.8
20.6
430-4
Reservoir
3.76
2.51
0.056
8.45
7.80
74.7
1.3
-
3.0
21.0
430-37
Reservoir
3.82
2.51
0.022
6.46
5.35
75.1
1.1
-
2.6
21.2
430-41
Reservoir
3.79
2.51
0.048
8.65
7.65
76.1
0.8
-
2.7
20.4
YL-1
Outcrop
3.81
2.51
0.22
12.0
11.68
78.2
-
-
-
20.3
YL-2
Outcrop
3.80
2.51
0.32
11.8
11.1
77.6
-
-
-
22.4
SX-1
Outcrop
3.82
2.51
0.18
8.97
8.86
80.4
1.5
-
-
18.1
SX-2
Outcrop
3.80
2.51
0.15
8.75
8.76
83.7
1.4
-
-
14.8
SX-6
Outcrop
3.81
2.51
0.23
9.68
8.97
77.9
1.1
5.0
16.0
96
The abbreviations for the full names of minerals can be found in the reference 28.40 TCCM represents the total content of clay minerals; is gas
97
permeability， is helium porosity， is water porosity，wt% is weight percent.
98
3.2 Pore-throat combination morphology by SEM
99
As can be known from SEM results, interparticle pores are filled with clay minerals (Fig.1(a)(k)), secondary quartz
100
(Fig.1 (a)), and calcite (Fig.1(h)), forming residual interparticle pores. Framework minerals, such as quartz and feldspar, are
101
dissolved in the diagenesis process, forming dissolution pores (Fig.1(e)). Intergranular pores (Fig.1(f)) are supported by
102
authigenous minerals, such as chlorite, kaolinite. Microfractures are scarce and have narrow width (Fig.1(c)). In summary,
103
three pore throat combinations were identified, including necking throats (Fig.1 (b) (d)), shrink throats (Fig.1(h)) and flaky
104
throats (Fig.1(g)). No tubal throat was observed by this SEM, however, tubal throats are always formed in clay minerals
105
filling pores. The three throat types are numerous in tight sandstones and tend to associate with pores as “ink-bottle” pore
106
throat structures (Fig.1 (b) (d) (h) (g)). Throats are sometime filled with authigenous minerals which reduces the
107
petrophysical performances of tight reservoirs. At the same time, intergranular pores (Fig.1(f)) and dissolution pores
108
(Fig.1(d)) in authigenous minerals are connected with interparticle pores, improving the petrophysical performances of tight
109
reservoirs.
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110 111
112
113
a
b
c
d
e
f
g
h
k
Fig.1 Typical pore types and throat types found in subsurface samples from Chang 6
3.3 NMR results
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The NMR technique can detect the hydrogen nucleus in pores or fractures of porous medium.17 The larger the value of
115
NMR T2, the bigger pore and vice versa. NMR tests combined with centrifuge are performed on samples in Table 1 and the
116
results are shown in Fig.2 and Apendix A. Three types of NMR T2 distributions at 100% water saturated condition were
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classfied after taking NMR experiments on samples, including unimodal T2 distribution (type I), bimodal T2 distribution
118
with two similar peaks (type II), and bimodal T2 distribution with a higher right peak (type III). Water in big pores tends to
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be free while water in tiny pores is hard to be displaced. In order to better represent pore fluid characteristics, we
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respectively define the left peak and right peak of bimodal NMR T2 distribution as immovable peak and movable peak. 41
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Through statistics, six subsurface samples belong to type III, which exhibits a lower immovable peak and a higher movable
122
peak. The larger the permeability is, the higher the movable peak and the lower the immovable peak. At the same time, the
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immovable peaks of three types are all found at values lower than 1 ms when movable peaks are respectively located at 15
124
ms, 40 ms, 70 ms, which indicates a wide PSD. And as permeability increases, the movable peaks moves to the right
125
gradually.
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When water saturated samples are placed into the centrifuge, water will be displaced by the centrifugal force. The
127
relationship between the centrifugal radius and the centrifugal force satisfies the Washburn equation, 26, 42 which can be
128
expressed as follow,
129
Pcentri =
−2σ cosθ rcentri
(1)
130
where Pcentri is the centrifugal force, MPa; rcentri is the minimal pore radius for water to discharge at the pressure Pcentri , µm;
131
σ is
132
centrifugal radii corresponding to the centrifugual force in section 2.2 are 1 µm, 0.3 µm, 0.1 µm, 0.05 µm,and 0.03 µm. The
133
NMR T2 distributions after centrifugations correspond to residual fluid distribution.
the gas-water interface tension, mN / m; θ is the gas-water wetting angle, 0°. Hence, based on Equation (1), five
134
For concision, we place one of each type in Fig.2 and the remaining are attached in Appendix A. As can be seen, two
135
distinct same features exist among type I. Firstly, the original peaks move to left and the amplitudes of peaks become lower
136
with increasing centrifugal force. Secondly, patterns of NMR T2 distributions change from unimodal ones to bimodal ones
137
with a higher peak and a lower peak after being centrifuged at 208 psi. Movable water in pores with T2 less than 10ms was
138
almost completely displaced, indicating a good connectivity in type I cores. When another two larger centrifugal forces were
139
conducted, an immovable peak and a slowdown peak are formed. The pattern of type II changes from a symmetrical
140
bimodal one to an asymmetrical bimodal one: the immovable peak slows down a little continuously when the movable peak
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141
changes to an immovable one with the centrifugal force increasing.The pattern of type III changes from an asymmetrical
142
bimodal one to a whole peak and a semi-one, and then changes to a unimodal pattern. Although the overall trends of three
143
core plugs among type III are similar, discrepancies also exist. Take 302-31 and 430-10 for example, the right peak of
144
302-31 decreases quickly in the first three centrifugations and then no change occurs. Two Peaks of 430-10 decrease
145
uniformly during five centrifugations, especially the immovable peak. The changes in NMR T2 distributions during
146
centrifuging reflect the characteristics of six changes in pore-throat connectivity, which will be discussed later. 1000
The signal intisity(1)
900 800 700 600 500
Saturated by water
Type I (YL-1 )
21psi 84psi 208psi 418psi 696psi
400 300 200 100 0 0.01
0.1
1
10
Transverse relaxation time(ms)
100
1000
The signal intisity(1)
450 400
Saturated by water
350
21psi
300
84psi
250
Type II (SX-2)
208psi 418psi
200
696psi
150 100 50 0 0.01
0.1
1
10
Transverse relaxation time(ms)
100
1000
800 700
The signal intisity(1)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
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600 500 400
Type Ⅲ (431-15)
300 200 100 0 0.01
147
Saturated by water 21psi 84psi 208psi 418psi 696psi
0.1
1
10
Transverse relaxation time(ms)
100
1000
Fig.2 NMR T2 distributions of samples before and after centrifugations (others are shown in Appendix. A)
148
Overall, two common features exist among three types. First, the signal of small NMR T2 value intensifies, indicating
149
that water invades the tiny pores during centrifugation. Second, the amount of water in big pores and throats is significantly
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decreased until less water is left. Differences also exist between outcrop samples (type I and type II) and reservoir samples
151
(type III). For example, the original peak of type I and the immovable peak of type II move to left with centrifugal force
152
increasing, while the immovable peaks of type III hardly change. In addition, the signal intensity of NMR T2 with value
153
higher than 10 ms decreases at first, finally stabilizes and remains unchanged when the centrifugal force increases. It
154
demonstrates that pore throat connectivity between two peaks is poor in tight reservoirs. The comparison between outcrop
155
and subsurface samples indicates that the pore structure is more complex in subsurface samples ,which leads to fluid in the
156
subsurface samples is more difficult to be displaced.
157
4 Discussion
158
With the help of C, NMR T2 distribution can be successfully transformed into pore size distribution. However, previous
159
methods of obtaining C are not suitable for tight formation. In this section, a new method of obtaining C is proposed to
160
calculate PSD based on the centrifugation results and detailed anylysis is discussed as follows.
161
4.1 The new method to calculate C
162
As NMR T2 represents residual fluid distribution at the corresponding centrifugal force, the difference between any two
163
NMR T2 curves reflects movable fluid distribution. By virtue of this principle, we take SX-6, SX-2 and 431-15 as
164
representatives to obtain MFD in the five throat intervals which are (1, + ∞ ), (0.3, 1), (0.1, 0.3), (0.05, 0.1), (0.03, 0.05) µm.
165
The identical centrifugal time and the centrifugal force of each sample satisfying Equation (1) strictly were guaranteed
166
during centrifugations among these samples. Therefore, we assume that throat intervals will not change from sample
167
to sample in our experiments. And the results are shown in Fig.3.
168
From Fig.3, positive peaks and negative ones both exist in each MFD curve. Especially negative peaks appear only
169
when NMR T2 values are small. The negative value indicates that fluids have moved into these pore spaces while positive
170
value indicates that fluids have been displaced out of these pore spaces. Three conditions should occur when fluid can be
171
displaced: First, pore radius should be equal to or larger than the centrifugal radius. Second, the connected throat should be
172
equal to or larger than the centrifugal radius. Third, water should not be not detained by water-wet minerals.43 The possible
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reason for negative peaks to occur is that a lot of ink-bottle pores are developed in tight sandstones. And the second
174
condition for fluid to be displaced is not met, then water in ink-bottle pores will be stuck in throats and smaller pores (Fig.4),
175
resulting in a negative value in the MFD curves. Therefore, each transverse relaxation time value (T2c) of the right endpoint
176
of negative interval interestingly corresponds to the minimum pore can be displaced, whose radius corresponds to the
177
centrifugal radius ( ). 350 >=1µm
Signal intisity(1)
300
SX-6
0.3µm-1µm 250
0.1µm-0.3µm
200
0.05µm-0.1µm
150
0.03µm-0.05µm
100 50 0 -50
0.01
0.1
1
10
100
1000
-100
Transverse relaxation time(ms)
Signal intisity(1)
200
>=1µm
SX-2
0.3µm-1µm 150
0.1µm-0.3µm 0.05µm-0.1µm
100
0.03µm-0.05µm
50
0 0.01
0.1
1
10
100
1000
-50
Transverse relaxation time(ms) 300
Signal intisity(1)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
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>=1µm
431-15
250
0.3µm-1µm
200
0.1µm-0.3µm 0.05µm-0.1µm
150
0.03µm-0.05µm 100 50 0 -50
0.01
0.1
1
10
100
1000
-100
Transverse relaxation time(ms)
178
Fig.3 NMR distributions of movable water of each throat intervals
179
In NMR T2 analysis, the key technology is to transform NMR T2 distribution into PSD effectively. As is known to all,
180 181
the relationship between T2 and pore throat radius (R) satisfies the equation as follow, 44 R = ρ FST2
(2)
182
where ρ is only related to pore surface property and FS is the shape factor, therefore, there exists a constant relationship
183
between T2 and R for the same formation as follow,
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184 185
(3)
R = CT2
Therefore, C can be calculated according to Equation (4) derived from Equation (3),
186
C =
Rc T2 c
(4)
187
Fcentrifugal 188 189 Water
190
Fcapillary 191 192
Fig.4 Water is detained in the throat of an ink-bottle pore-throat structure
193
Table 2 The conversion factor (C) calculated based on the proposed method The centrifugal force (psi) sample
24
84
208
418
696
SX-2
0.44
0.21
0.14
0.10
0.21
SX-6
0.77
0.25
0.20
0.23
0.38
YL-1
0.36
0.26
0.13
0.10
0.10
302-31
0.83
0.83
0.28
-
-
431-15
0.25
0.37
0.23
0.23
-
430-10
0.95
-
0.26
0.10
0.10
430-41
0.27
0.20
0.29
0.39
0.05
430-37
0.65
0.17
0.25
0.17
-
430-4
0.33
0.37
0.41
0.55
0.21
194 195
As can be seen from the above transformation method, the most important technology is to determine parameter C
196
effectively. Different from traditional methods, this method makes use of transverse relaxation time value (T2c) of the right
197
endpoint of negative intervals and corresponding centrifugal radius (Rc) to determine C, which is more accurate and
198
effective for tight sandstones. The calculation results can be seen in Table 2. However, C for outcrop and subsurface
199
samples at the first centrifugation is much larger than others, which is contradictory with the statement that C for one
200
formation should be theoretically identical.19 The possible reason is that the movable fluid for the first centrifugation is
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stored in large pores extending in a long range and connecting a great deal of tiny pores and throats (Fig.4).In this way,
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202
water will be always detained into these connected, smaller throats and pores than corresponding centrifugal radius,
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resulting in a smaller T2c and a larger C . Because a better homogeneity in outcrops, the discrepancy among outcrop ones is
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less. Values of C for different cores from the same formation should be closed.19 At the same time, pore and throat show less
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difference with centrifugal force increasing and the situation in Fig.4 will not happen. Based on all above, C calculated at
206
208 psi in Table 2 was selected to be the conversion factor for the Chang 6 formation in this paper.
207 208 5
25
MIP
20
NMR
4
15
3
10
2
5
1
Water saturation(%)
Mecury saturation(%)
302-31
0
0 1
10
100
1000
10000
100000
1000000
Pore radius (nm)
209
5 MIP
431-15
25
NMR
20
4 3
15
2 10
1
5
Water saturation(%)
Mercury saturation(%)
30
0
0 1
10
100
1000
10000
100000
1000000
Pore radius (nm)
210
MIP NMR
430-10
20
30-10
15
4 3
10
2
5
1
Water saturation(%)
5
25
Mercury saturation(%)
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60
Page 12 of 23
0
0 1
10
100
1000
10000
100000
1000000
211
Pore radius (nm)
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Fig.5 Pore size distribution by pressure-controlled porosimetry and NMR transverse relaxation time for three core samples
213
Hence, PSDs can be converted through multiplying NMR T2 by C in Table 2. The comparison of the PSD by MIP and
214
the PSD by NMR for three subsurface samples is presented in Fig.5. Comparison results can be seen from Fig.5, only one
215
peak with radii
