Insights into the pores types and wettability of shale gas reservoir by

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Insights into the pores types and wettability of shale gas reservoir by nuclear magnetic resonance: Longmaxi Formation, Sichuan Basin, China Liang Wang, Rong Yin, Liqiang Sima, Ling Fan, Hua wang, Qinqin Yang, and Linlin Huang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b02107 • Publication Date (Web): 07 Aug 2018 Downloaded from http://pubs.acs.org on August 9, 2018

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Insights into the pores types and wettability of shale gas reservoir by nuclear magnetic resonance: Longmaxi Formation, Sichuan Basin, China †

†

†

‡

†

†

Liang Wang,*, Rong Yin, Liqiang Sima,*, Ling Fan, Hua Wang, Qinqin Yang, Linlin Huang †

†

State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University, Chengdu 610500, People’s Republic of China;

‡

Central Sichuan Mining District, Southwest Oil & Gas Field Company, PetroChina, Suining, Sichuan 834000, China;

Abstract: Reservoir properties, such as pore types and wettability, are essential for shale gas reservoir evaluation. However, the advanced nuclear magnetic resonance (NMR), which has been routinely used in the reservoir’s petrophysical characterizations, is barely used to estimate above properties in shale gas reservoir. In this study, several sets of specially designed NMR measurements, together with total organic carbon (TOC), X-ray diffraction (XRD), field emission scanning electron microscopy (FE-SEM), and contact angle tests are used to study the pore types and wettability of Longmaxi shale gas reservoir. Results show that the NMR transversal relaxation time (T2) spectrum can be used to characterize pore types and wettability of gas shale. Three identified T2 spectral peaks (0.01-0.4 ms, 0.4-15 ms, and >15 ms) are separately corresponding to the organic pores, inorganic pores, and micro-fractures, which is consistent with the results of FE-SEM. The T2 spectra in “as received” and water/oil-imbibition states qualitatively prove that the micro-wettabilities of organic pores, inorganic pores, and micro-fractures are oil-wet, 1

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water-wet, and mixed-wet, respectively. In addition, a novel wettability index is defined to reflect the micro-wettability of pores quantitatively. The dominant minerals and TOC jointly affect the pore wettability index. The dominant minerals and TOC show good correlations to the wettability index of the inorganic and organic pore, whereas no obvious correlations to the wettability index of micro-fracture. In contact angle measurements, the water and oil droplets show different behaviors on the surface of shale specimens, which qualitatively indicates that the macro-wettability of Longmaxi gas shale is mixed-wet (both water-wet and oil-wet) and more prone to be oil-wet. After analyzing the theory of characterizing macro-wettability by NMR, a new NMR-based model is proposed to characterize the macro-wettability quantitatively. In summary, this study proposes novel methods and models to characterize the pore types and wettability, which expand the use of NMR in shale gas reservoirs.

Keywords Longmaxi Formation; shale gas; pore; wettability; nuclear magnetic resonance; reservoirs

1 INTRODUCTION With the growing shortage of clean energies, the shale gas has recently become a research hotspot.1-11 As a kind of clean energy, shale gas is regarded as an important energy supplement.12-17 At present, great challenges in the exploitation of shale gas still exist due to the complicate pore types and their wettabilities.3-4,18-20 The wettabilities of pore types will directly affect the residual gas saturation, relative permeability, and hydraulic fracturing operation in shale gas reservoir.21-26 Thus, a thorough understanding and effective characterization of the wettabilities are crucial for the evaluation and exploitation of shale gas. The pore types are conventionally observed by the optical thin sections.6-7, 22-23, 27-30 However, the resolution of the traditional optical sections is limited to be approximately 0.23 µm.31 The nano-scale pores in the shale gas reservoir limit the application of the traditional optical sections. The scanning electron microscopy (SEM) is well-suited to study the pore types in shale gas reservoir since it can detect the pores from nano- to micro-scale.27,32 However, it has the spatial limitation in observing area.22,33 Additionally, the non-mechanical polishing like argon ion beam milling should be used to obtain ultra-flat samples and avoid 2


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abrasion marks, smearing grain boundaries, embedment of grit into the surface of the sample,7,34-35 which will lead to the poor-quality of SEM images. The reservoir’s wettability is usually characterized by contact angle, USBM wettability index, and Amott wettability index.20,25,36-37 The Amott and USBM methods require the fluid percolation and displacement in experiments. Thus, these two techniques are limited to measure the reservoir’s wettabilities due to the ultra-low permeability of shale gas reservoir.24,38 The contact angle test provides an effective way to characterize the wettability of shale gas reservoir. Whereas, due to the strong wettability heterogeneity in gas shale, the results of the contact angle vary with the testing spot on the sample surface.39 The spontaneous imbibition of water and oil, on the other hand, indirectly and qualitatively estimate the wettability of shale gas reservoir.25,36-37 But the method of the spontaneous imbibition cannot characterize the wettability quantitatively. Moreover, the above techniques only reflect the macro-wettability of shale gas reservoir and cannot detect the micro-wettabilities of pore types.20,25,36-37,40 Additionally, the experimental techniques mentioned above have common shortcomings of the time consuming and sample destruction. Thus, it is necessary to seek for a simple, rapid, and non-destructive method to study the pores types and wettabilities in shale gas reservoir. Different from the experimental techniques mentioned above, NMR technique is well known for its simplicity, rapidity, and non-destruction, as well as reliability and sound repeat-ability in core tests.8,19,41 This technique has been widely applied to characterize the porosity, permeability, pore structures in sandstone and carbonate reservoirs. 42-48 As to the shale gas reservoir, the previous studies mainly focus on the response characteristics of NMR and its application in the porosity and pore structure estimation. In one of the earliest NMR studies on shale, Martinez1 conducted the studies on the variation of NMR porosity before and after fluid saturation. Further, Sigal and Odusina8 observed a fixed spectral peak at about 1 ms in the NMR T2 spectra of core plugs, which were collected from the eastern Barnett Basin. They speculated that the signal of the fixed spectral peak originated from clay bound water or residual water in micropores. Lately, Tinni et al.49 analyzed the variable characteristics of T2 spectrum during the oil and water migration in pores of the Haynesville and Woodford shales; Xu et al.50 found that the NMR T2 spectra and porosities are greatly affected by the echo spacing and waiting time. Tan et al.51 established the NMR petrophysical interpretation method for the shale gas reservoir. Sigal41, as well as Milad and Manika, 19 proposed methods to characterize the pore size distributions of Barnett, Middle Bakken, and Three Forks shales. To our 3


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knowledge, the characterization of the pores types and wettabilities by NMR has not been systematically studied yet in the shale gas reservoir. Taking the Longmaxi gas shale as a research target, this paper aims to insights into the pores types and wettability of shale gas reservoir by NMR. Specifically, the major objectives of this work are to (1) qualitatively characterize the pore types by the spectral peaks of T2 spectra; (2) reveal the micro-wettabilities of pore types by the different characteristics of T2 spectral peaks in oil- and water-imbibition states; (3) reveal the macro-wettability of gas shale and propose a novel NMR-based model to characterize the macro-wettability; (4) reveal the relationship between micro- and macro-wettability of gas shale

2 GEOLOGICAL SETTING Sichuan Basin is located at the southwest of China and covers an area of more than 18×104 km2 (Fig. 1a).52 It is a multiple-cycle sedimentary basin, confined on the north by Micang Mountain and Daba Mountain, on the south by E’mei-Liangshan Fold Belt, on the west by Longmen Mountain, and on the east by Hunan-Hubei-Guizhou Fold Belt (Fig. 1b).10,20,53-54 It is a prolific hydrocarbon region and is currently China's largest gas-producing region. The Jiaoshiba gas field, the study area in this study, is the first commercialized shale gas reservoir in China. The Jiaoshiba gas field is located in the Fuling District of Chongqing Municipality.27 Structurally, the Jiaoshiba gas field is both located in the east district of Sichuan Basin and on the west side of the basin boundary fault-Qiyueshan fault.22-23,52,55 The Jiaoshiba area has undergone several tectonic movements since the formation of Yangtze Paraplatform, which includes Caledonian (late Sinian-Silurian), Hercynian (Devonian-Permian), Indosinian (Triassic), Yanshanian (Jurassic-late Cretaceous), and Himalayan (Paleogene-Quaternary).27 In this area, the Devonian sediments are absent, and only a thin set of strata of Carboniferous sediments remains due to the erosion caused by the Caledonian orogeny. Cambrian, Ordovician, and Silurian layers are successively deposited until Hercynian deformation, which leads to the cessation of deposition on the top of lower Permian. The Silurian Longmaxi Formation has been regarded as the most critical gas-producing layer in JSB. The Longmaxi Formation deposited in an oxygen-poor marine sedimentary environment. From the early to the late stage of sedimentation, the degree of hypoxia, the depth of sedimentary water, and the paleo-productivity have a similar trend. Oxygen content in water increases, the depth of water becomes 4


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shallower, and paleo-productivity decreases. During the initial sedimentation of the Longmaxi Formation, sedimentary waters have the conditions of anaerobic, deeper water, and high paleo-productivity that can form high-quality shales.22 Finally, a set of dark mud shale rich in silicon and organic matter developed in the Longmaxi Formation. For more detailed geological situations, please refer to the related literature of Wei et al.22 and Guo et al.23.

54

Fig. 1 Basic information about the geological setting and core samples (modified by Zhao et al. ); (a) location of the Sichuan Basin in China; (b) location of the study area in Sichuan Basin; (c) the stratigraphic columns in the study area.

3 MATERIALS AND METHODOLOGY 3.1

Samples Core samples of Longmaxi gas shale were drilled from the central of Jiaoshiba gas field, Sichuan

Basin. The depths of these core samples are 2370-2410m (Fig.1c). The vitrinite reflectances of the Longmaxi gas shale varies in the range of 1.84-3.5%,27,52 which indicates that it is over-mature (Ro>2.0%).2 5


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The thermal maturity shows that the Longmaxi Formation is in the dry gas generation window.18 Eight core samples were selected and numbered as H1, LM1, H8, LM2, H12, LM3, H10, and LM4. To make sure the representative of the core samples, the variabilities of TOC and inorganic composition were taken into consideration. To ensure the comparability of experimental results among different measurements, each sample was cut into chips and plugs and followed a specially designed experimental process. The chips were chosen to conduct the FE-SEM, XRD, TOC, and contact angle tests. The plug was further cut into parallel plugs with a diameter of 2.54 cm and length from 3 to 4 cm. Table 1 shows the final core numbers of the parallel plugs. Several sets of NMR measurements in different states were conducted on the parallel plugs. Table 2 shows that the core samples have variable inorganic composition and TOC contents, which demonstrate the representative of core samples. Table 1 The core numbers of the parallel plugs. Core no.

spontaneous water- imbibitions

spontaneous oil-imbibitions

H1

H1-1

H1-2

H8

H8-1

H8-2

H10

H10-2

H10-1

H12

H12-1

H12-2

LM1

LM1-1

LM1-2

LM2

LM2-2

LM2-1

LM3

LM3-2

LM3-1

LM4

LM4-1

LM4-2

3.2. XRD and TOC measurements An X’pert PRO was used to analyze the mineralogical compositions of the core samples. The scanning measurements were performed at a rate of 2°/min in the 3-90° range, and then the mineral compositions were estimated by analyzing the peaks.40 The TOC was measured by a LECO CS230 carbon/sulfur analyzer. For this purpose, samples should be crushed into less than 100 meshes particles, and then introduced to hydrochloric acid to remove the carbonates.10 In the next step, the samples were washed by distilled water and put into the oven at 70oc until dried. At this stage, samples would be ready to put into LECO for TOC measurement. Overall, the preparation, analysis and interpretation procedures for the mineralogy and TOC were conducted following the Chinese Oil and Gas Industry Standard (SY/T) 5163-2010 and Chinese 6


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National Standards (GB/T) 19145-2003, respectively.

3.3. FE-SEM analysis To obtain ultra-flat samples for the FE-SEM measurement, the argon ion beam milling is used to polish the core samples by the Hitachi Ion Milling System IM4000 with an acceleration voltage of 3 kV. After the surface polishing, the samples were coated with gold at a thickness of 10 nm to provide a conductive surface. The FE-SEM imaging of pores was performed with an FEI Quanta 200F. This method can directly observe the microscopic pore types, morphology, and distribution.6-7,18 Because of the high resolution but limited vision area of FE-SEM, sufficient images were obtained to eliminate potential randomness.

3.4. Contact angle measurements The contact angles, representing the macro-wettability of shale gas reservoir, were measured following the methodology proposed by Fu et al.56 and Sun et al.57. This methodology can avoid inaccuracy of contact angle measurement caused by a testing spot on the flat surface. According to this methodology, core samples were powdered to be 200 mesh. The shale powder was then placed into a forming mold and subjected to a high-pressure compression.56-57 And then, a testing specimen with a flat surface was obtained. After that, the contact angles of the air-fluid-rock system were measured by an optical contact angle measuring device. The contact angle was calculated by Eq. (1).

= 2 tan ( )

(1)

Where θ is contact angle, °; h and a are the height and the bottom radius of the water/oil droplet respectively, m; In the contact angle measurement, the fluids of oil (kerosene) and water (deionized water) were used.

3.5. NMR measurements In order to make the properties of core samples unchanged, the core samples were not dried or subjected to any particular cleaning procedure before NMR measurements. The NMR T2 spectra of parallel plugs in their “as received” state were firstly obtained; “As-received” in this context means that the core plugs were drilled from the core material using pressurized air as drilling fluid and then conduct the NMR measurement without any further treatment. After that, the parallel plugs were separately conducted the 7


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spontaneous oil- and water-imbibitions following the methods of Gao and Hu.25 When the weights of the parallel plugs no longer increase, the process of the spontaneous oil- and water-imbitions was regarded to be finished. And then, the NMR measurements were conducted on these core samples. The dodecane and sodium chloride solution were used for the spontaneous oil- and water-imbibitions, respectively. The bulk relaxation time of dodecane and sodium chloride solution were also measured to investigate its influence on the T2 spectra. The NMR measurements were carried out with the 2 MHz Lim-MRI-D2 spectrometer produced by Beijing Limecho Technology Co., Ltd. The Carr-Purcell-Meiboom-Gill (CPMG) echo trains were used in the measurement, and then Butler-Reeds-Dawson algorithm was adopted for the inversion of the T2 spectrum.46-47 For shale gas reservoir, the NMR signals are weak and difficult to detect.9,

50

Thus,

acquisition parameters should be properly designed to ensure the quality of NMR signals. To enhance the signal to noise ratio of the NMR signals, the numbers of scan and echoes were set as 128 and 4096, respectively. What is more, the waiting time (TW) and the echo time (TE) are also important since they directly affect the spectral shapes and NMR porosities.50 The samples are randomly selected to investigate the effects of variational TW and TE on the NMR results. The NMR results with different TW and TE have similar characteristics, which is illustrated by the core sample of H8-2 (Fig. 2). Fig.2a shows that the TE affects the NMR measurement result significantly, that is, the fast relaxation components cannot be fully detected if the TE is longer than 0.06 ms. Similarly, the maximum recovery of the polarized longitudinal relaxation time signal cannot be fully obtained when TW is shorter than 6 ms (Fig. 2b). Thus, to obtain the fast relaxation components and maximum recovery of the polarized longitudinal relaxation time signal, the TE and TW were chosen as 0.06 ms and 6 s, respectively. The workflow for describing the preparation and NMR measurements of the core plugs is presented in Fig. 3.

8


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300

300

TE=0.06ms,TW=6s TE=0.1ms,TW=6s TE=0.2ms,TW=6s TE=0.3ms,TW=6s

250 200

TW=8s,TE=0.06ms TW=6s,TE=0.06ms TW=4S,TE=0.06ms TW=2s,TE=0.06ms

(b)

250 Signal amplitude

(a)

Signal amplitude

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150 100

200 150 100 50

50 0

0

0.01

0.1

1 10 T2 (ms)

100 1000

0.01

0.1

1

10

100 1000

T2 (ms)

Fig. 2 The T2 spectra of H8-2 with variable TE and TW; (a) The T2 spectra of H8-2 with variable TE; (b) The T2 spectra of H8-2 with variable TW.

Select and number the core samples Drill core plug (with 2.54 cm in diameter and 6 - 8 cm in length ) Cut the core plug into parallel plugs (with 2.54 cm in diameter and 3 - 4 cm in length) Polish the two sides of the parallel plugs and further number the parallel plugs Randomly select the core plug and conduct the NMR measurement by variational TW and TE to get the optimal acquisition parameters NMR measurements of the parallel plugs in their “as received” state

Spontaneous oil- imbibitions

Spontaneous water- imbibitions

for one of the parallel plugs

for other parallel plug

Are the weight of core plug become stable? (by checking the difference of weight)

No

Yes NMR measurements of the parallel plugs in their oil- or water- imbibitions state

Fig. 3 The workflow for describing the preparation and NMR measurements of the core plugs.

4 RESULTS

9


No

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4.1 Mineralogy and TOC of shale gas reservoir Table 2 shows that the quartz and clay are the dominant minerals in the samples. The quartz contents are in the range of 29.17%-57.81% with an average content of 42.51%. The clay contents range from 20.32% to 59.41% with an average 37.81%. The quartz shows a negative correlation to the clay, that is, the quartz contents increase with the decrease of clay contents. In addition, the carbonate minerals and feldspars account for small proportions of the mineralogy, the average contents of which are 7.86% and 9.12%, respectively. The illite is the dominant clay mineral. The contents of illite, chlorite, and mixed layer illite/smectite are in ranges of 12.6-33.27%, 5.22-20.79%, and 0.88-7.46%, respectively. TOC is in range of 0.58-5.42%. The average content of TOC is 2.59%, which indicates an organic-rich gas shale. Table 2 Mineralogical compositions and TOC content of core samples The relative percentage of minerals (wt.%) TOC Core no.

Mixed-layer Quartz

Feldspars

Calcite

Dolomite

Pyrite

Illite

Chlorite

(wt.%)

illite/smectite H1

42.70

7.78

3.93

3.81

3.30

19.74

2.96

15.79

3.50

H8

45.15

14.84

7.19

0.00

3.41

19.54

4.63

5.22

2.59

H10

57.81

10.69

3.81

3.52

3.85

12.60

1.63

6.10

5.42

H12

38.91

11.46

3.08

3.61

2.03

22.54

4.60

13.78

1.41

LM1

29.17

7.83

14.78

1.01

3.36

30.99

0.88

11.98

2.33

LM2

52.91

8.44

5.62

5.92

2.21

13.86

4.60

6.43

3.03

LM3

39.80

6.62

4.87

0.00

3.53

24.56

7.46

13.17

1.89

LM4

33.62

5.27

0.00

1.70

0.00

33.27

5.35

20.79

0.58

Average

42.51

9.12

5.41

2.45

2.71

22.14

4.01

11.66

2.59

4.2 Pore morphology of shale gas reservoir by FE-SEM images The observation of pore morphology by FE-SEM analyses were performed on all core samples. The FE-SEM images show that the pores mainly range from nano- to micro-scale. According to the descriptive classification scheme by Loucks et al.6 and Guo et al.23, both organic pores and inorganic pores (intraparticle pores, intercrystalline pores, and interparticle pores) are observed within organic matters (OM) and mineral matrix, respectively. The organic pores are irregular and elliptical with pore sizes mainly in 10


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ranges of 5-200 nm (Figs. 4a-b), which are formed during the thermal cracking of organic matter to hydrocarbons.22-23 The intraparticle (IntraP) pores are mainly developed within quartz grains with angular or linear shapes, the pore size of which often exceeds 100 nm (Fig. 4c). This kind of pore type is not commonly found in the FE-SEM images, which indicates the un-development of IntraP pores in Longmaxi shale gas reservoir. The intercrystalline (InterC) pores are found within pyrite crystals (Fig. 4d), most of which are filled with OM or clay minerals. The residual InterC pores within incompletely-filled pyrite framboids usually have irregular shapes with a diameter of several hundreds of nanometers to several microns (Fig. 4d). The InterC pore morphology observed in this study is consistent with the results by Yang et al.27. The interparticle (InterP) pores are developed between minerals particles, the pore size of which varies from 100 nm to several hundreds of nanometers (Fig. 4e). Two kinds of micro-fractures are observed and shown in Fig. 4f and Fig. 4g, respectively. The micro-fracture in Fig. 4f occurs at the edge of organic matters and other minerals. This kind of micro-fracture is formed due to the rock failure under abnormal pressure generated during the organic evolution,23 The other kind of micro-fracture in Fig. 4g is formed due to the shrinkage and volume reduction of rocks in the diagenetic process. The width of micro-fractures varies from hundreds of nanometers to several microns. In summary, the gas storage space in Longmaxi shale gas reservoir can be further classified into three categories, that is, organic pores, inorganic pores (InterC pores, IntraP pores, and InterP pores), and micro-fractures. The sizes of these three pore types follow the order of organic pores < inorganic pores < micro-fractures. Specifically for the inorganic pores, the size of InterP pores is smaller than that of InterC pores. Our observations about the pore sizes of these pore types in the Longmaxi shale gas reservoir are consistent with the results of Wei et al.22 and Guo et al.23.

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(a)

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(b) Fig.3b

OM

OM pores

OM pores

(d)

(c)

Intra Pores

OM pores

OM InterC

pores

Pyrite Framboids

(e)

(f) InterP pores OM

OM Micro-fracture

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(g)

Micro-fracture

Fig. 4 Pore morphology of Longmaxi shale gas reservoir by FE-SEM analyses; (a) and (b) organic pores in sample H9 are widely developed within organic matter (OM); (c) IntraP pores of sample LM1 within quartz grains; (d) InterC pores of sample H3 within incompletely-filled pyrite framboids; (e) InterP pores of sample H12 between clay minerals; (f) micro-fracture occurs between organic matter and clay minerals; (g) micro-fracture developed in clay minerals.

4.3 The contact angles of shale gas reservoir The contact angle tests of the core samples have similar characteristics, which are illustrated by the core sample of H10 and LM4 (Fig. 5). Fig. 5a and 5b show that the water droplets maintain a stable shape on the surface of the shale specimens and it is easy to measure the water contact angles. On the contrary, the oil droplets spread out rapidly when contacting the surface of the shale specimens. Since the oil droplets spread out on the surface of the shale specimens rapidly, it is hard to measure the accurate contact angles during the measurements. Thus, only the water contact angles are recorded to reflect the wettabilities of shale gas reservoirs. The water contact angles are presented in Table 3. Table 3 shows that the water contact angle varies from 29.53º to 53.34º with an average value of 37.55º. (a)

(b)

(c)

(d)

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Fig. 5 The water (oil) contact angles of core samples. (a) the water contact angle of H10 is 53.34º; (b) the water contact angle of LM4 is 29.53º; (c) and (d) the oil droplets spread out on the surface of the shale specimen of H10 and LM4, respectively. Table 3 The water contact angle of core samples. The contact angle of

The contact angle of cosθ

Core no.

cosθ

Core no.

water θ (º)

water θ (º)

H1

36.50

0.80

LM2

41.50

0.75

H8

40.50

0.76

LM3

32.50

0.84

H10

53.34

0.60

LM4

29.53

0.87

H12

32.00

0.85

Average

37.55

0.79

LM1

34.50

0.82

4.4 Characteristics of NMR T2 spectra 4.4.1 Characteristics of NMR T2 spectra in “as received” states Fig. 6 shows the NMR T2 spectra in “as received” state. The T2 values (X-axis), commonly plotted logarithmically spaced from 0.01ms to 1000 ms,10,20 are proportional to the pore size of core samples. The amplitude of the T2 spectra (Y-axis) is proportional to the number of protons in pores and indirectly corresponds to the incremental porosity.10,58 The parallel plugs show consistent characteristics in the range of T2 values and incremental porosity (Fig. 6). Thus, the parallel plugs show consistent reservoir property, and the T2 spectra between parallel plugs are comparable. The T2 spectra show bimodal characteristics with two spectral peaks (P1 and P2) distributed in the ranges of 0.01–0.4 ms and 0.4–15 ms, respectively. The incremental porosity with T2 greater than 0.4 ms is obviously smaller than that with T2 less than 0.4 ms, which implies the irreducible fluid in the “as received” states.

14


Page 15 of 36

0.30 H1-1

(a ) 0.25

Incremental porosity (%)

Incrementa l porosity (%)

0.30 H1-2

0.20 0.15 P1 0.10 0.05

P2 0.01

0.1

1 10 T2 (ms)

100

0.15

P1

0.10 0.05

P2 0.01

0.1

1 10 T2 (ms)

100

1000

0.30 (c)

(d)

H10-1

0.25

Incremental porosity(%)


H8-1

0.20

1000

0.30 H10-2

0.20 0.15 P1

0.10 0.05

H12-1

0.25

H12-2

0.20 0.15 P1

0.10 0.05

P2

P2 0.00

0.00 0.1

1 10 T2 (ms)

100

0.01

1000

1 10 T2 (ms)

(f)

LM1-1

0.25

LM1-2

0.20 P1

0.15

0.1

100

1000

0.30

(e)


0.01

0.30

H8-2

(b) 0.25

0.00

0.00


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

Energy & Fuels

0.10 0.05 P2 0.00

LM2-1

0.25

LM2-2

0.20 0.15 P1 0.10 0.05 P2 0.00

0.01

0.1

1

10 T2 (ms)

100

1000

0.01

15


0.1

1

10 T2 (ms)

100

1000

Energy & Fuels

0.30

0.30 (g)

(h)

LM3-1

0.25



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 16 of 36

LM3-2

0.20 P1

0.15 0.10 0.05

P2 0.00

LM4-1

0.25

LM4-2

P1 0.20 0.15 0.10 0.05 P2 0.00

0.01

0.1

1

10 T2 (ms)

100

1000

0.01

0.1

1

10 T2 (ms)

100

1000

Fig. 6 Characteristics of NMR T2 spectra in “as received” states

4.4.2 Characteristics of NMR T2 spectra in oil-imbibition states Fig. 7 shows the NMR T2 spectra in oil-imbibition states. The NMR T2 spectra display a triple-peak pattern. The peak one (P1), peak two (P2), and peak three (P3) distribute in ranges of 0.01–0.4 ms, 0.4–15 ms, and >15 ms, respectively. When the T2 values are less than 0.08 ms, the NMR spectra in “as received” and oil-imbibition states show similar incremental porosity, whereas obvious discrepancies in the incremental porosities occur when the T2 values are more than 0.04 ms. Thus, it can be concluded that the dodecane enters the pores with T2 values larger than 0.04 ms. The amplitude of P1 increases significantly during the process of oil-imbibition, whereas the P2 has a slight increase in the amplitude. Additionally, a new spectral peak (P3) appears after oil imbibition. The amplitude of P1 is much bigger than those of P2 and P3, which indicates that the dodecane significantly enters into the pores with T2 in range of 0.01–0.4 ms, but slightly into the pores with T2 in ranges of 0.4–15 ms and >15 ms.

16


Page 17 of 36

0.30

"As received" state Dodecane imbibition

(a)

0.25



0.30

no. H1-2

P1 0.20 0.15 0.10

P2

0.05

0.25


P1

no. H8-2

0.20 0.15 0.10

P2

0.05

P3

0.00

0.01

0.1

1 10 T2 (ms)

100

0.01

1000

0.30

0.30

(c)

"As received" state

0.25



(b)

P3

0.00

Dodecane imbibition

no. H10-1

0.20 P1 0.15 0.10

P2

0.05

0.1

(d)

1 10 T2 (ms)

100

1000


0.25

no. H12-2

0.20

P1

0.15 0.10 0.05

P2

P3

P3

0.00

0.00 0.01

0.1

1 10 T2 (ms)

0.01

100 1000

0.1

1 10 T2 (ms)

100

1000

0.30

0.30 0.25

0.25


Dodecane imbibition

no. LM1-2

0.20

P1

0.15 0.10 0.05

P2

"As received" state

(f)

"As received" state

(e) Incremental porosity (%)

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

Energy & Fuels

P3

Dodecane imbibition

0.20

no. LM2-1 P1

0.15 0.10 0.05

P2

P3

0.00

0.00 0.01

0.1

1

10 T2 (ms)

100

0.01

1000

17


0.1

1

10 T2 (ms)

100

1000

Energy & Fuels

0.30

0.30 (g) 0.25

Dodecane imbibition

P1

0.20

no. LM3-1

0.15 0.10 0.05

P2


(h)

"As received" state



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 18 of 36

P3

0.00

0.25 P1

no. LM4-2

0.20 0.15 0.10 0.05

P2

P3

0.00 0.01

0.1

1 10 T2 (ms)

100 1000

0.01

0.1

1 10 T2 (ms)

100 1000

Fig. 7 The NMR T2 spectra in oil-imbibition states

4.4.3 Characteristics of NMR T2 spectra in water-imbibition states The NMR T2 spectra in water-imbibition states can be divided into two categories, as displayed in Fig. 8. The NMR T2 spectra of LM2-2, H1-1, H10-2 and H8-1 show a triple-peak pattern, the P1, P2, and P3 distribute in ranges of 0.01–0.4 ms, 0.4–15 ms, and >15 ms, respectively. On the contrary, the NMR T2 spectra of LM1-1, H12-1, LM4-1, and LM3-2 are bimodal, and the first peak (P1+P2) and the second peak (P3) distribute in the ranges of 0.01–15 ms and >15 ms, respectively. The incremental porosities of T2 spectra in “as received” and water-imbibition states show discrepancies when T2 values are more than 0.08 ms. Thus, the water only enters the pores with corresponding T2 values larger than 0.08 ms. In addition, the peak amplitudes show an obvious increase when the T2 is in the range of 0.4–15 ms but a slight increase in the range of 0.01–0.4 ms. Thus, the water mainly enters the pores with corresponding T2 values in the range of 0.4-15 ms.

18


Page 19 of 36

0.30

Water imbibition

0.25

no. H1-1 0.20

P2

P1

0.15 0.10 0.05

P3

0.25

no. H8-1 0.20

P2

0.15

P1

0.10 0.05

P3

0.00

0.00 0.01

0.1

1 10 T2 (ms)

100

0.01

1000

0.30 Water imbibition

no. H10-2

0.20

P2

0.15 P1

0.10 0.05

1 10 T2 (ms)

100

1000

"As received" state

(d)


0.25

0.1

0.30

"As received" state

(c)


"As received" state Water imbibition

(b) Incremental porosity (%)


0.30

"As received" state

(a)

P3

0.25

Water imbibition

no. H12-1

0.20 (P1+P2) 0.15 0.10 0.05

P3 0.00

0.00 0.1

1 10 T2 (ms)

0.30 0.25 (P1+P2)

0.1

1 10 T2 (ms)

100 1000

0.30 "As received" state Water imbibition

(f)

no. LM1-1

0.15 0.10 0.05

0.01

1000


(e) 0.20

100


0.01


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

Energy & Fuels

P3

0.25

no. LM2-2

0.20 0.15

P1

P2

0.10 0.05

P3

0.00

0.00 0.01

0.1

1 10 T2 (ms)

100

0.01

1000

19


0.1

1

10 T2 (ms)

100

1000

Energy & Fuels

0.30

(P1+P2)


0.25 0.20

0.30


(g) Incremental porosity (%)

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

no. LM3-2

0.15 0.10 0.05

Page 20 of 36

P3

0.00


(h)

0.25

(P1+P2)

no. LM4-1

0.20 0.15 0.10 0.05

P3

0.00 0.01

0.1

1

10 T2 (ms)

100 1000

0.01

0.1

1

10 T2 (ms)

100

1000

Fig. 8 The NMR T2 spectra of the core samples in their water- imbibition states

5 DISCUSSIONS 5.1 Characterization of the pore types by NMR T2 spectra Theoretically, the T2 can be expressed as follows:49,51

=

+ +

(2)

Where T2B is the bulk relaxation time; T2S is the surface relaxation time; T2D is the diffusion relaxation time; the unit of them is a millisecond. In Eq. (2), the T2D can be calculated by8, 48

=

( )

(3)

Where D is the diffusion coefficient of sodium chloride solution; γ is the gyromagnetic ratio of a proton; G is the field strength gradient; For a homogeneous internal field gradient and short TE used in our NMR measurement, the calculated value of 1/T2D is approximately 6.57×10-5 ms-1, which is small enough to be neglected. Therefore, Eq. (2) becomes

=

+ =

+

(4)

Where ρ2 is the pore surface relaxivity, S/V is pore surface to volume ratio. The T2B measurements of the imbibition fluids show that the T2B of dodecane and sodium chloride solutions are 550 ms and 800 ms, respectively (Fig. 9). Then, the 1/T2B are approximately 1.8×10-3 ms-1 and 1.2×10-3 ms-1 for dodecane and sodium chloride solution, respectively. Due to the small values of 1/T2B, the bulk relaxation’s effect on T2 should be neglected. Thus, the T2 can be written as 20


Page 21 of 36

=

(5)

Eq. (5) shows that only surface relaxation contributes to the T2 in shale gas reservoir, which is consistent with the research of Milad and Manika19. They realize that the surface relaxation controls the T2 of organic shale in Middle Bakken and Three Forks Formations. Generally, the S/ V can be expressed as

=

(6)

Where Fs is a dimensionless shape factor. 59 r is pore radius, nm; Combining Eqs. (5) and (6), we get r=ρ2FsT2

(7)

Eq. (7) shows that the T2 is proportional to pore size and the spectrum represents the pore size distribution. Since the pore sizes of the pore types in Longmaxi shale gas reservoir follow the order of organic pores < inorganic pores < micro-fractures, the pore types can be correspondingly characterized by the T2 spectra. Specifically, the spectral peaks of P1, P2, and P3 mainly corresponds to the organic pores, inorganic pores, and micro-fractures, respectively. The relationships between pore types and T2 spectra can be further demonstrated by the spontaneous oil/water-imbibition characteristics of these pore types. 0.6

1.0

(a)

0.5

(b) Dodecane

Signal amplitude

Signal amplitude

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

Energy & Fuels

0.4 0.3 0.2

0.8

Sodium chloride solution

0.6 0.4 0.2

0.1 0.0

0.0 10

100

1000 T2 (ms)

10

10000

100

1000

10000

T2 (ms)

Fig. 9 The T2B of dodecane and sodium chloride solution; (a) the T2B of dodecane is 550 ms; (b) the T2B of sodium chloride solution is 800 ms.

5.2 Characterization of the pore wettability by NMR T2 spectra 5.2.1 Qualitative characterization of the pore wettability by NMR T2 spectra Odusina et al.60, Sulucarnain et al.38, Zhang et al.61, and Liang et al.62 pointed out that the 21


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Page 22 of 36

micro-wettabilities of pore types in organic shale will directly affect the spontaneous imbibition behaviors toward oil and water. During the oil-imbibition, oil-wet pores will imbibe oil spontaneously. Similarly, the water-wet pores will imbibe water spontaneously during the water-imbibition. For the pores with mixed wettability, they will imbibe both oil and water simultaneously. The differential behaviors toward oil and water are caused by the hydrophilic and hydrophobic characteristics of pore types. Fig. 7 shows that the amplitude of P1 increases significantly during the oil-imbibition, whereas the P2 and P3 have no obvious changes. It can be explained that the pores corresponding to the P1 preferentially imbibe oil and should be oil-wet. As discussed above, the P1 corresponds to the organic pores. Thus, the organic pores are proved to be oil-wet. In the same way, the inorganic pores can be proved to be water-wet since the amplitude of P2 increases significantly in water-imbibitions (Fig. 8). Unlike the amplitudes of P1 and P2 increasing separately in the oil- and water-imbibition, the amplitude of the P3 increases obviously not only in the water-imbibition but also in oil-imbibition (Fig. 7 and Fig. 8). Since the micro-fractures correspond to the P3, it can be concluded that the micro-fractures imbibe both oil and water simultaneously and are prone to be mixed-wet. The pore morphology of gas shale by FE-SEM images shows that two kinds of micro-factures are developed in the gas shale, as displayed in Fig. 4f and Fig. 4g, respectively. In Fig. 4f, the micro-fracture is formed during the organic evolution. This kind of micro-fracture has an affinity for oil and prone to be oil-wet. However, the other kind of micro-fracture in Fig. 4g is formed by the shrinkage and volume reduction of the inorganic matrix and prone to be water-wet. Thus, the different origins of micro-fractures results in the mixed-wet wettability.

5.2.2 Quantitative characterization of the pore wettability by NMR T2 spectra Based on the NMR T2 spectra of the parallel plugs in their “as received” and water/oil- imbibition states, the imbibed volume of oil (Io) and water (Iw) for organic pores, inorganic pores, and micro-fractures can be calculated as

!

= " )*+ S(T%&' )dt − " )*+ S(T/0 )dt

1

= " )*+ S(T2 )dt − " )*+ S(T/0 )dt

),-

),-

),-

),-

(8) (9)

Where Io and Iw are the imbibed volumes of oil and water respectively, %. S(Toil), S(Tw), and S(Tre) are the incremental porosity distribution function, which are associated with the T2. T2min and T2max are the minimal 22


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Energy & Fuels

and maximal T2 values for pore types. The T2min and T2max for organic pores are 0.01 ms and 0.4 ms, respectively. Similar, the T2min and T2max are 0.4 ms and 15 ms for inorganic pore, and 15ms and 1000ms for micro-fractures. In order to reflect the pore affinity toward oil and water, we define a new index referred to as pore wettability index for oil (PWIo) and water (PWIw). The PWIo and PWIw are defined as 34

!

=

34

1

=

56 57

57 56

;

=

;

"; )*+ (6,8 )9:"; )*+ (15 ms, correspond to the organic pores, inorganic pores, and micro-fractures, respectively. (3) The T2 spectra in “as received” and oil/water-imbibition states prove that the micro-wettabilities of organic pores, inorganic pores, and micro-fractures are oil-wet, water-wet, and mixed-wet, respectively. The mixed-wettability of the micro-fractures is attributed to their different origins. (4) The pore wettability index has correlations to the TOC and minerals. The PWIo of organic pore has a negative correlation to clay minerals, but positive correlations to TOC and quartz. On the contrary, PWIw of the inorganic pore is positively correlated to clay minerals but negatively correlated to TOC and quartz. The wettability index of micro-fracture has no obvious correlations to the TOC and minerals. (5) The water droplet maintains a stable shape on the surface of the shale specimens, and the oil droplet spreads out rapidly when contacts the surface of the shale specimen. This different behaviors of water and oil droplets on the surface of shale specimens indicate that the macro-wettability of Longmaxi 29


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shale gas reservoir is mixed-wet (water-wet and oil-wet) and more prone to be oil-wet. A new NMR-based model is proposed to characterize the macro-wettability of Longmaxi gas shale. (6) The interior relationship between micro- and macro-wettability of gas shale shows that the organic pore and the inorganic pore jointly contribute to the macro-wettability of gas shale, whereas the micro-fractures do not have obvious contributions to the macro-wettability of gas shale.

AUTHOR INFORMATION

Corresponding Authors *E-mail:[email protected]. Phone:+86-183-821-06629. *E-mail:[email protected]. ORCID Liang Wang: 0000-0002-3958-8986 Liqiang Sima: 0000-0003-0309-8667 Notes The authors declare no competing financial interest.

ACKNOWLEDGMENTS

This research was supported jointly by an Open Fund of State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation (Grant No. PLN1503), National Science and Technology Major Project of China (no. 2016ZX05052), National Natural Science Foundation of China (Grant No. 41504108), Fund Project of China Postdoctoral Science Foundation (Grant No. 2015M582568), and Chongqing Land Bureau Science and Technology Planning Project (Grant No. CQGT-KJ-2014017). 30


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References

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(12) U. S. Energy Information Administration (EIA). Technically recoverable shale oil and shale gas resources: an assessment of 137 shale formation in 41 countries outside the united sates. 2013. Http:// www.eia.gov/analysis/studies/worldshalegas. (13) Washburn, K. E.; Cheng, Y. Detection of intermolecular homonuclear dipolar coupling in organic rich shale by transverse relaxation exchange. J. Magn. Reson. 2017, 278, 18–24. (14) Washburn, K. E. Relaxation Mechanisms and Shales. Concept Magn. Reson. A. 2014, 43A(3), 57–78. (15) Washburn, K. E.; Birdwell, J. E. Updated methodology for nuclear magnetic resonance characterization of shales. J. Magn. Reson. 2013, 233, 17–28. (16) Korb, J.; Nicot, B.; Louis-Joseph, A.; Bubici, S.; Ferrante, G. Dynamics and Wettability of Oil and Water in Oil Shales. J. Phys. Chem. C. 2014, 118, 23212− 23218. (17) Martínez, G. A.; Davis, L. A. Petrophysical Measurements on Shales Using NMR. Paper SPE 62851 presented at the SPE/AAPG Western Regional Meeting, 2000. (18) Milliken, K. L.; Rudnicki, M.; Awwiller, D. N.; Zhang, T. Organic matter-hosted pore system, Marcellus formation (Devonian), Pennsylvania. AAPG Bull. 2013, 97, 177-200. (19) Milad, S.; Manika, P. Effect of mineralogy on nuclear magnetic resonance surface relaxivity：A case study of Middle Bakken and Three Forks formation. Fuel 2015, 161,197-206. (20) Wang, L.; Fu, Y.; Li, J.; Sima, L.; Wu, Q.; Jin, W.; Wang, T. Experimental study on the wettability of Longmaxi gas shale from Jiaoshiba gas field, Sichuan Basin, China. J. Petrol. Sci. Eng. 2017, 151, 488-495.

(21) Anderson, W. G. Wettability literature survey part 5: The effects of wettability on relative permeability. J. Can. Petrol. Technol. 1987, 39(11), 1453-1468. (22) Wei, X. F.; Liu, R. B.; Zhang, T. S.; Liang, X. Micro-pores structure characteristics and development control factors of shale gas reservoir: A case of Longmaxi Formation in XX area of southern Sichuan and northern Guizhou. Natural Gas Geosci. 2013, 24(5),1048-1059. (in Chinese) (23) Guo, X. S.; Li, Y. P.; Liu, R. B.; Wang, Q. Characteristics and controlling factors of micro-pore structures of Longmaxi shale play in the Jiaoshiba area, Sichuan Basin. Natur Gas Ind 2014, 34(6), 9-16. (24) Xu, M.; Dehghanpour, H. Advances in understanding wettability of gas shales. Energ. Fuel. 2014, 28, 32


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Insights into the pores types and wettability of shale gas reservoir by

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