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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

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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

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into three types (I, II, III). Among which, type I and type II show a better pore connectivity than type III with NMR T2

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distribution of a higher movable peak and a lower immovable peak. The optimum centrifugal force for the Chang 6 tight

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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

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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

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qualitatively evaluating pore throat connectivity in tight sandstones. Petrophysical characterization by NMR technique

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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

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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

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porosimetry (RCP) and nitrogen adsorption, have a limited range of measurement of pore size.5, 8, 9 Therefore, some authors

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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

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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

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cores provides information on PSD, porosity, permeability, and moveable fluid percentage.15-18 In order to obtain pore size

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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,

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transformation between PSD and NMR T2. Nowadays, there are many methods to determine C such as the empirical method,

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the similarity method and the T2cutoff method. C obtained by the empirical method is only applicable to a certain area

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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

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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

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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

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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

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centrifugal force to apply to the Chang 6 formation is 418 psi. Movable water is mainly stored in pores distributed around

60

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.

67

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

74

measurement parameters are as follow: echo spacing, 0.1 ms; waiting time, 300 ms; echo numbers, 6000; numbers of scans,

75

32. All experiments were conducted at room temperature of 293.15K under a relative humidity of 60%. The procedures are

76

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

81

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

87

XRD results (Table 1) show that all samples are rich in feldspar and quartz. Six subsurface samples contain especially a

88

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

90

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

92

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

114

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

117

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

121

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

123

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.

126

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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173

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

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endpoint of negative intervals and corresponding centrifugal radius (Rc) to determine C, which is more accurate and

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effective for tight sandstones. The calculation results can be seen in Table 2. However, C for outcrop and subsurface

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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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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

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208 psi in Table 2 was selected to be the conversion factor for the Chang 6 formation in this paper.

207 208 5

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MIP

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NMR

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3

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Water saturation(%)

Mecury saturation(%)

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Pore radius (nm)

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MIP NMR

430-10

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30-10

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4 3

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Water saturation(%)

5

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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

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1000000

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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

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Hence, PSDs can be converted through multiplying NMR T2 by C in Table 2. The comparison of the PSD by MIP and

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the PSD by NMR for three subsurface samples is presented in Fig.5. Comparison results can be seen from Fig.5, only one

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peak with radii