The Analysis of Differential Saturation in Shale Oil Accompanied by an Enhanced Classification of Fluid Distribution within the Pore
Alok Kumar Singh
Round 1
Reviewer 1 Report
Comments and Suggestions for AuthorsCharacterization of differential saturation of shale oil from different types of pores and fractures with a refined classification of fluid distribution pore (processes-3180484)
The point-wise comment given below about the paper-
1) There are several grammatical and sentence arrangement mistakes present in the article.
2) Authors should rewrite the abstract
3) Comments are marked in the PDF file
4) The authors used the NMR to determine the pore. There are many instruments available for pore determination. BET is one of the tools that can give more accurate pore characterization, and authors should include the result of BET analysis in the manuscript.
Recommendation: Major reason required in the manuscript.
Comments for author File: 
Comments.pdf
The point-wise comment given below about the paper-
1) There are several grammatical and sentence arrangement mistakes present in the article.
2) Authors should rewrite the abstract
3) Comments are marked in the PDF file
4) The authors used the NMR to determine the pore. There are many instruments available for pore determination. BET is one of the tools that can give more accurate pore characterization, and authors should include the result of BET analysis in the manuscript.
Recommendation: Major reason required in the manuscript.
Author Response
Comment 1: Define briefly what is the meaning of 14-d, what is n-dodecane test.
Response to comments 1: Thanks very much for your comments. In this study, the shale oil saturation measurements were launch 14 days, and the shale oil is instead with the n-dodecane.
Comment 2: Check again 100mm × 3000mm or φ 100 mm × 3000 mm.
Response to comments 2: Thanks very much for your comments and suggestions. We have checked the manuscript, and the modified content is as follow,
Low-velocity drive saturated is a common method for saturating tight sandstones with fluids. However, shale-type shale is extremely tight, and conventional saturated fluid methods are difficult to apply. In this study, the method of saturating fluids under stratigraphic temperature (60 ℃) and pressure (20 MPa) conditions was used to saturate the shale samples with fluids. A self-designed high-temperature and high-pressure containment device was used to saturate the shale oil, the maximum temperature and pressure can reach to 120 ℃ and 60 MPa respectively. The size of the high-temperature and high-pressure closed vessel is φ 100 mm × 3000 mm, and the outside of the vessel is wrapped with an insulating device, with a temperature control accuracy of ± 0.1 ℃, and the simulated oil used for the experiment is n-dodecane. The experimental procedures are as follows:
Comment 3: Which instrument is used for the identification of these pores, define briefly in method section.
Response to comments 3: Thanks very much for your comments. The modified content is as follow,
There are many types of pores in shale, and there are more classification methods, the more typical ones are the pore classification methods of Loucks et al., Slatt and O'Neal and Yu et al [33-35]. Based on the previous pore classification for shale, it can be found that the storage space in the Chang 7 Member shale can be roughly distinguished into several types, such as clay mineral intergranular pores, intraparticle microfractures, organic matter pores, organic matter fractures, and fractures developed in the edges of the inorganic and organic matter with the MIRA3 high-resolution field-emitting electron microscopy produced in Czech Republic (Figure 2).
Comment 4: Mark the pores and fractures on these image for more clarity.
Response to comments 4: Thanks very much for your comments. The pores and fractures in the figures have been enhanced, and the modified contents are as follow,
Figure 2. The various types of pores and fractures in the shale sample
((a) clay mineral intergranular pores and intraparticle microfractures; (b) the fractures developed in the edges of the inorganic and organic matter; (c) intraparticle microfractures; (d) organic matter pores)
Comment 5: Define V shape properly in the figure by marking the axes and also define the V shaped characteristics.
Response to comments 5: Thanks very much for your comments. The V shape features a fluctuant tend of the saturation oil. As shown in Figure 4, at the initial period of 6 days, the S features as continuously decrease. Subsequently, it presents as increase, and this feature as an uppercase “V”. Therefore, we named it as V-shape in this study. The modified contents are as follows,
The liquid hydrocarbon saturation of SS-1 and SS-2 shale samples showed an obvious three-stage structure with the continuation of the saturation time. The liquid hydrocarbon saturation showed a rapid increase in the first 4 d of n-dodecane hydrocarbon saturation, then the liquid hydrocarbon saturation showed a slow increase, and after the liquid hydrocarbon saturation time of more than 10 d showed a rapid increase in the liquid hydrocarbon saturation, and the SS-1 and SS-2 shale samples were finally saturated with 26.92% and 31.46% of the liquid hydrocarbon saturation, respectively. The SS-1 and SS-2 shale-type shale samples showed high liquid hydrocarbon saturation, while the absolute amount of liquid hydrocarbons was still low considering the low porosity of the shale. As for the liquid hydrocarbon saturation degree, it shows significantly V-shape, which is similar to the liquid hydrocarbon saturation degree (Figure 4).
Comment 6: Rewrite the sentence.
Response to comments 6: Thanks very much for your comments. The mistakes and unclear expressions are modified, and the modified content is as follow,
With the enhanced fluid distribution pore classification method, four different types of pores in shale were distinguished. Larger-sized fractures correspond to layer fractures in shale, while smaller-sized pore-seam systems can be distinguished mainly as seepage fractures, micropores, and adsorption pores (Figure 6). Layer fractures are larger in size, and fluids in layer fractures are mainly free-flowing by gravity; seepage fractures are inorganic and organic fractures in shale, which can flow to a certain extent by overcoming capillary forces under certain external stresses; fluids in micropores are more comfortable with capillary forces, and fluids in adsorbent pores are almost immovable. Comparing SS-1 and SS-2 shale samples, it can be found that liquid hydrocarbons are mainly stored in micropores and seepage fractures, and micropores are the main storage space for liquid hydrocarbons; the number of layer fractures and adsorption pores is less, and the amount of liquid hydrocarbons that can be stored in them is also less (Figure 6).
Comment 7: Clarity needed.
Response to comments 7: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
Overall, the differential saturation of liquid hydrocarbons in pore-fracture system can be roughly categorized into three types. Type I, the liquid hydrocarbons distributed in the layer fractures. The layer fractures are the fractures features as centimeter level, the fluid in this part of spaces is weakly influenced by the capillary force. In contrary, it is more likely affected by the change of external stress. Therefore, the mobility of shale oil in the layer fractures features as fluctuant (Figure 7(d1), Figure 7(d2)). Type II is represented by liquid hydrocarbons in adsorption pores and seepage fractures, and the saturation characteristics of liquid hydrocarbons in these two types of storage spaces feature as V-shape (Figure 7(a1), Figure 7(a2), Figure 7(c1), Figure 7(c2)), reflecting the dynamic equilibrium between capillary force and external stress. The seepage fractures in SS-2 shale sample is much more developed than that in SS-1 shale sample, and the retention effect of capillary force features stronger than that of the external stress on liquid hydrocarbon. Therefore, SS-2 sample needs a longer time to achieve equilibrium (Figure 7(c1), Figure 7(c2)). The adsorption pores showed strong retention of liquid hydrocarbons for SS-1 and SS-2 shale samples (Figure 7(a1), Figure 7(a2)). Type III is the fluid distributed in the micropores, which features the smaller pore aperture. As the main storage space for liquid hydrocarbon, the saturation of liquid hydrocarbon shows a continuous increase (Figure 7(b1), Figure 7(b2).
Comment 8: Define properly here and correlate with the figure-7 in more detailed way.
Response to comments 8: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
Overall, the differential saturation of liquid hydrocarbons in pore-fracture system can be roughly categorized into three types. Type I, the liquid hydrocarbons distributed in the layer fractures. The layer fractures are the fractures features as centimeter level, the fluid in this part of spaces is weakly influenced by the capillary force. In contrary, it is more likely affected by the change of external stress. Therefore, the mobility of shale oil in the layer fractures features as fluctuant (Figure 7(d1), Figure 7(d2)). Type II is represented by liquid hydrocarbons in adsorption pores and seepage fractures, and the saturation characteristics of liquid hydrocarbons in these two types of storage spaces feature as V-shape (Figure 7(a1), Figure 7(a2), Figure 7(c1), Figure 7(c2)), reflecting the dynamic equilibrium between capillary force and external stress. The seepage fractures in SS-2 shale sample is much more developed than that in SS-1 shale sample, and the retention effect of capillary force features stronger than that of the external stress on liquid hydrocarbon. Therefore, SS-2 sample needs a longer time to achieve equilibrium (Figure 7(c1), Figure 7(c2)). The adsorption pores showed strong retention of liquid hydrocarbons for SS-1 and SS-2 shale samples (Figure 7(a1), Figure 7(a2)). Type III is the fluid distributed in the micropores, which features the smaller pore aperture. As the main storage space for liquid hydrocarbon, the saturation of liquid hydrocarbon shows a continuous increase (Figure 7(b1), Figure 7(b2).
(a) SS-1 (b) SS-2
Figure 7. The differences of S in various types of pores and fractures in the shale samples
Comment 9: Adsorption or micropores? Check properly with section 3.4.
Response to comments 9: Thanks very much for your comments. The micropores and seepage fractures are the dominant spaces in the shale, the saturation oil degree in the seepage fractures and adsorption pores feature as V-shape. However, the quantity of the adsorption pores is less, which contribute less to the saturation degree, and the shale oil saturation degree is mainly determined by the fluid distributed in the micropores and seepage fractures. To express it more clearly, we have modified as follows,
The liquid hydrocarbon saturation degree of the shale-type shale shows a three-stage pattern, while the liquid hydrocarbon saturation degree exhibits a V-shaped characteristic, which is closely related to the differential saturation effect of the two dominant types of storage spaces, micropores and seepage fractures.
Comment 10: There are several grammatical and sentence arrangement mistakes present in the article.
Response to comments 10: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content are marked red, which we hope can reach your approval.
Comment 11: Authors should rewrite the abstract.
Response to comments 10: Thanks very much for your comments. The abstract has been rewritten, which we hope clearly expressed the dominant content of this study, and the modified contents are as follow,
Abstract: Shale oil saturated by high temperature (20MPa) and high pressure (60℃) can not only realize the efficient saturation of shale, but also invert the shale oil return and drainage characteristics under the stratum temperature and pressure due to the heterogeneity of shale formations. In this study, the Chang 7 Member shale samples were collected, and the high-temperature and high-pressure containment device was utilized to saturate the shale oil efficiently under 20 MPa and 60 ℃, the differences of liquid hydrocarbon saturation and the degree of liquid hydrocarbon saturation for different types of pores and fractures in the shale were quantitatively characterized with a low-field nuclear magnetic resonance (NMR) technology. The results show that under the condition of formation temperature (60℃) and pressure (20MPa), shale oil saturation can be reached after 14 d of saturation in the shale samples. The shale oil saturation process can be roughly divided into three stages according to the various saturation rates, the rapid saturation stage, the slow saturation stage, and the second rapid saturation stage respectively, and the degree of saturation of shale oil is characterized by a V-shape. The shale oil distributed into four types of pore-fracture system, adsorption pores, micropores, seepage fractures and layer fractures respectively. Additionally, the fluid dominantly distributes in the micropores and seepage fractures, the shale oil saturation degree of the micropores features a continuous increase, while that for the seepage fractures presents a V-shape, which determines the shale oil saturation characteristics of the shale finally.
Comment 11: Comments are marked in the PDF file
Response to comments 11: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content are marked red, all of the comments are responsed in Comment 1 to Comment 9.
Comment 12: The authors used the NMR to determine the pore. There are many instruments available for pore determination. BET is one of the tools that can give more accurate pore characterization, and authors should include the result of BET analysis in the manuscript.
Response to comments 12: Thanks very much for your comments. We admit that the BET method can describe the pore structure characteristics well. However, it should be noticed that the BET method would destroy the shale samples. The shale features heterogeneity, with the various shale samples, the results may different. In this study, the shale samples would be measured repeatedly, and the BET method may not adopt it. However, NMR is a non-destructive measurement technology, then it is utilized in this study.
Author Response File: Author Response.pdf
Reviewer 2 Report
Comments and Suggestions for AuthorsKindly follow in the manuscript my comments and act accordingly.
Thank you.
Comments for author File: Comments.pdf
English must be revised.
Author Response
Comment 1: I recommend the following title: The analysis of differential saturation in shale oil accompanied by an enhanced classification of fluid distribution within the pores.
Response to comments 1: Thanks very much for your comments. Now, the title of the revised manuscript has been modified, and the modified content is as follow,
The analysis of differential saturation in shale oil accompanied by an enhanced classification of fluid distribution within the pore
Comment 2:
2.1 Identify the level of saturation, be specific as what are the values of temp. and pressure?
2.2 Switch to heterogeneity of shale structure or formations.
2.3 Check the English grammar.
2.4 What is the saturation pressure?
2.5 Elaborate on these characteristics.
2.6 How did you define these 3-phases?
2.7 Is there any parameter involved?
2.8 Elaborate this kind of shape?
2.9 Kindly revise the grammar and be more specific.
These contents should be modified in the Abstract section.
Response to comments 2: Thanks very much for your comments and suggestions. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
Abstract: Shale oil saturated by high temperature (20MPa) and high pressure (60℃) can not only realize the efficient saturation of shale, but also invert the shale oil return and drainage characteristics under the stratum temperature and pressure due to the heterogeneity of shale formations. In this study, the Chang 7 Member shale samples were collected, and the high-temperature and high-pressure containment device was utilized to saturate the shale oil efficiently under 20 MPa and 60 ℃, the differences of liquid hydrocarbon saturation and the degree of liquid hydrocarbon saturation for different types of pores and fractures in the shale were quantitatively characterized with a low-field nuclear magnetic resonance (NMR) technology. The results show that under the condition of formation temperature (60℃) and pressure (20MPa), shale oil saturation can be reached after 14 d of saturation in the shale samples. The shale oil saturation process can be roughly divided into three stages according to the various saturation rates, the rapid saturation stage, the slow saturation stage, and the second rapid saturation stage respectively, and the degree of saturation of shale oil is characterized by a V-shape. The shale oil distributed into four types of pore-fracture system, adsorption pores, micropores, seepage fractures and layer fractures respectively. Additionally, the fluid dominantly distributes in the micropores and seepage fractures, the shale oil saturation degree of the micropores features a continuous increase, while that for the seepage fractures presents a V-shape, which determines the shale oil saturation characteristics of the shale finally.
Comment 3:
3.1 I do not see NMR in the abstract.
3.2 I do not see these keywords as well.
Response to comments 3: Thanks very much for your comments. The key words have been modified, and the modified content is as follow,
Keywords: shale oil; NMR; V-shape; saturation degree; Chang 7 Member
Comment 4: I recommend reading the following paper, because one condition might be due to compressibility: A potential parameter for a non-Darcy form of two-phase flow behaviour, compressibility related Busahmin, B., Maini, B. International Journal of Engineering and Technology(UAE), 2018, 7(3), pp. 126–131.
Response to comments 4: Thanks very much for your comments. We have study the recommend literature. In this study, the literature 7 is cited to explain the three various states of oil in the shale, the compressibility is a special condition recommend by the reviewer. However, in this section we just want to show the common characteristics of the oil in the shale.
Comment 5:
5.1 Double check the highlight.
5.2 Check the grammar in here.
5.3 Check the grammar.
5.4 Double check the grammar.
5.5 Be more specific to shale!
5.6 Shale formations rather than pores!
5.7 I do not recommend to use any of the pronouns in the whole manuscript.
5.8 Use proper verbs.
5.9 I recommend revising grammatically the highlighted paragraph.
These contents should be modified in the Introduction section.
Response to comments 5: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
Shale oil, as an important unconventional oil and gas resource, is widely developed in North America and Eurasia [1]. China's shale oil resources are mainly distributed in the Bohai Bay Basin, Junggar Basin, Ordos Basin, and Songliao Basin, and so on. The poor tectonic environment and variable depositional environments led to a number of challenges in China's continental-phase shale oil exploration and development [2-5].
Liquid hydrocarbons in shale usually exist in three phases, free, adsorbed, and dissolved respectively [6], and are distributed in shale formations in the form of spots or layers. Adsorbed and dissolved oils are usually associated with kerogen or solid asphalt, with a high content of asphaltene and non-hydrocarbon fractions; free oils are usually stored in mineral pores, with a high content of saturated hydrocarbon fractions [7]. Under certain technical conditions, the free oil can be extracted generally, which belongs to movable oil [8]. Nuclear magnetic resonance (NMR), as a non-destructive measurement technology, is widely used in the field of oil and gas mobilization research [9-11], and the NMR becomes a mature technical to study the mobility of shale oil [12]. The 1-dimensional scanning of NMR T2 spectrum and the 2-dimensional scanning of T1-T2 spectrum can better respond to the shale oil distribution status, mobilization range, and so on [13-17]. The shale skeleton itself also features NMR signals intensity, and its background signals should be fully considered when shale oil movability analysis is conducted [18,19]. According to the differences of the NMR spectra, the oil production status and oil production quantity can be quantitatively characterized [20-21].
Shale pore structure, degree of fracture development, and formation pressure are key factors in qualitatively evaluating shale oil mobility [22]. Shale oil is mainly enriched in pores smaller than 100 nm, in which the lower limit of pore size for free oil enrichment is 5 nm [23]; Zhu et al. concluded that the critical conditions by analyzing the changes in oil content and pore structure of shale before and after soluble organic matter extraction, the content of movable oil should be greater than 0.7%, and average pore size should be greater than 12.1 nm [24]; Han et al. compared the change of the aperture of pore in shale before and after the soluble organic matter extraction, and found that the micropores volume of the sample increased significantly after extraction, which led to the conclusion that shale oil is mainly stored in micropores with pore sizes below 2 nm [25]. NMR technology is also unique in characterizing shale pore structure. Using the combined characterization of high-pressure mercury pressure, gas adsorption and NMR, the conversion between transverse relaxation time and pore radius can be effectively realized [26]. Based on the combined characterization of multi-testing methods, the pores in porous media reservoirs can be accurately classified. Hu et al. classified the pores in the tight sandstone reservoirs as micron-sized macropores, micron-sized micropores, submicron pores, and nano-pore types [27]; Peng et al. classified the pores in tight limestone into micropores, small pores, medium pores and large pores [28]; and Wang et al. classified the pores in tight sandstone reservoirs into three types, completely immobile pores, partially mobile pores and completely mobile pores based on the mobility characteristics [29]. In recent years, Li et al. finely classified the fluid-distributed pores in different types of tight sandstones with the NMR T2 spectra and fractal theory [30-32].
In this study, the shale samples collected from Chang 7 Member of the Yanchang Formation in Ordos Basin were taken as the research object, with a detailed measurements of properties and petrological of the shale samples, 14-d saturation of n-dodecane measurements were launched with the NMR technology under 20 MPa and 60 ℃, combined an enhanced classification method of the fluid distribution pore spaces, the shale oil saturation characteristics in various pores and fractures were quantitatively characterized.
Comment 6:
6.1 Switch to Methodology
6.2 Samples Collection
6.3 Elaborate more on these types of shale.
6.4 Check the grammar. what is the difference between shale gas and shale seams?
6.5 Switch to in addition rather than and, and......
6.6 Is shale a clay or vice versa?
6.7 I recommend to add an experimental setup before the procedures.
6.8 Well, coring is not drilling, I recommend using only from cores.......
6.9 Switch to however.....
6.10 What is the temperature used in here?
6.11 Elaborate on this kind of stratigraphic temp. and what are the pressure conditions?
6.12 Do you have any specific values for HTHP?
6.13 Switch to the experimental procedures are as follows:
6.14 Is injected!
6.15 Check the grammar.
6.16 Give some numbers in here.
6.17 I recommend to ignore this method and keep the selection of NMR as subtitle of the methodology.
6.18 With
6.19 Be specific.
6.20 Define the acronym in the text to facilitate readers.
6.21 From where?
6.22 Define the same in the text.
6.23 What is the rationale behind 70%?
6.25 Check the grammar.
6.26 Revise the title, use proper scientific terminologies.
6.27 Use proper language in writings!
6.28 Add proper verbs in the sentence. Elaborate on chirp time!
6.29 Use proper terms.
These contents should be modified in the Methodology section.
Response to comments 6: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
- Methodology
2.1. Samples Collection
The shale samples for this study were collected from the Chang 7 Member of the Yanchang Formation in Ordos Basin. There are three different types of shale in the Chang 7 Member, shale-type shale, textured shale and interbedded shale. The shale-type shale features as shale structure, the slit-sandstone and mudstone in the textured shale presents as interlayered, and the interbedded shale features the similar characteristics of the textured shale, while the thickness of slit-sandstone and mudstone commonly exceeds 10 cm. The shale sample used in this study are shale-type shale, and the shale samples were collected from a full-diameter core to avoid the possible errors. The shale-type shale is tight, with an extremely low porosity of 1.00%. However, the permeability of the shale-type shale is larger due to the presence of certain shale fractures, and the permeability of shale gas measurements is generally more than 0.10×10-3μm2 (Table 1). Clay minerals, plagioclase feldspar and quartz are the main inorganic minerals, and carbonate minerals (calcite and dolomite) and other brittle minerals such as pyrite are very low. In addition, the clay minerals are dominated by illite/smectite formation (Table 1).
Table 1. The properties parameters of the shale samples
|
Properties parameters |
Shale samples |
||
|
SS-1 |
SS-2 |
||
|
Porosity (%) |
0.99 |
1.01 |
|
|
Permeability (×10-3μm2) |
0.1231 |
0.1661 |
|
|
Inorganic minerals content (%) |
Quartz |
25.40 |
24.40 |
|
Potassium feldspar |
6.30 |
2.60 |
|
|
Plagioclase feldspar |
27.90 |
27.70 |
|
|
Calcite |
0.40 |
/ |
|
|
Dolomite |
0.60 |
/ |
|
|
Pyrite |
/ |
0.60 |
|
|
Muscovitize |
/ |
3.40 |
|
|
Clay minerals |
39.40 |
41.30 |
|
|
I/S |
36.20 |
27.00 |
|
|
It |
15.50 |
19.20 |
|
|
Kao |
18.50 |
18.80 |
|
|
C |
29.80 |
35.00 |
|
Note: I/S is the illite/smectite formation; It is the illite; Kao is the kaolinite; and C is the chlorite.
2.2. Experimental Procedures
Firstly, the shale samples were pretreated to remove the crude oil and water before the measurements. Conventional organic solvents such as benzene or carbon tetrachloride are used for pre-treatment of tight sandstone samples. However, the shale features a high content of clay minerals, and conventional organic chemical solvents can easily lead to shale hydration during the cleaning procedures, which may damage the shale samples. Therefore, the pre-treatment of shale samples was carried out heating in a drying oven under 80 ℃ in this study. The standard plunger samples obtained by low-speed wire cutting were placed in the drying box. The shale samples were weighed every 24 h using a high-precision balance, and the shale samples were considered to be dried when the quality of the shale samples varied within ± 0.001 g.
Low-velocity drive saturated is a common method for saturating tight sandstones with fluids. However, shale-type shale is extremely tight, and conventional saturated fluid methods are difficult to apply. In this study, the method of saturating fluids under stratigraphic temperature (60 ℃) and pressure (20 MPa) conditions was used to saturate the shale samples with fluids. A self-designed high-temperature and high-pressure containment device was used to saturate the shale oil, the maximum temperature and pressure can reach to 120 ℃ and 60 MPa respectively. The size of the high-temperature and high-pressure closed vessel is φ 100 mm × 3000 mm, and the outside of the vessel is wrapped with an insulating device, with a temperature control accuracy of ± 0.1 ℃, and the simulated oil used for the experiment is n-dodecane. The experimental procedures are as follows:
(1) Close the outlet end of the high-temperature and high-pressure containment device, the deionized water is injected into the high-temperature and high-pressure containment device from the injection end at a speed of 0.1 mL/min. The valve of the injection end would be closed when the pressure reaches to 20 MPa, the instrument would be maintained for 24 h to check the sealing;
(2) Launch the NMR T2 spectrum of the pre-treated standard plunger core to obtain the NMR T2 spectrum of the dry core;
(3) Place the shale core in a high-temperature and high-pressure containment device, the measurement pressure and temperature would be set as 20 MPa and 60 ℃ respectively; the NMR T2 spectrum scanning would be launched when the core samples is saturated for 48 h;
(4) Repeat step (3) with a step length of 2 d, and carry out NMR T2 spectra scanning of the shale core at different saturation times, 2 d, 4 d, 6 d, 8 d, 10 d, 12 d and 14 d respectively, and consider the core saturated when there is no obvious change in the NMR T2 spectra curve.
2.3. Selection of NMR Instrument Parameters
As a non-destructive measurement technique, NMR can realize multiple scans of the same sample to ensure the continuity and integrity of the experimental results. However, the selection of NMR instrument parameters has an important influence on the accuracy of sample. The NMR instrument used in this study is the PQ001 NMR instrument produced by Niumai, which adopts a permanent magnet with a magnetic field strength of 0.28 ± 0.03 T, an RF pulse frequency range of 1 MHz ~ 30 MHz, an RF frequency control accuracy of 0.1 Hz, with a probe coil diameter of 25mm. Before conducting the NMR test, the sampling frequency (SW), waiting time (TW), preamplification gain (PRG), number of scans (NS) and number of echoes (NECH) were selected.
SW should not be less than 100 KHz in most cases, the smaller SW is easy to lead to the loss of some effective signals in the samples, and usually the SE value should not be lower than 100 KHz. In this study, the SW was set to 125 KHz, 200 KHz, 250 KHz, 333 KHz, and 500 KHz respectively. The fast relaxation signal and high signal amplitude of nanopore space are taken as the criteria for selecting the preferred SW parameter, and the optimal SW value of 250 KHz is screened out. The PRG can improve the signal lightness of the samples effectively, and it is usually enough to reach 70% of the saturation value of the receiver, and it is better to set the PRG value of 1 in the present study. According to the principle of the highest preference for the consistency of the morphology of the NMR T2 spectra and the signal-to-noise ratio, TW, NS and NECH values were screened to be 2500 ms, 64 and 5000, respectively (Figure 1).
Figure 1. The NMR spectrums under various values of SW, PRG, TW, NS and NECH for shale sample
2.4. Classification of Fluid Distribution Pores
The shale features porous medium characteristics, meaning the shale presents fractal characteristics. The NMR transverse relaxation time T2 corresponds to the aperture of pores in the shale, which can be utilized to feature the fractal characteristics of the shale,
(Eq. 1)
where Svi is the cumulative signal amplitude percentage below T2i, %; Di is the fractal dimension at T2i, dimensionless; T2i is the transverse relaxation time, ms; and the T2max is the maximum transverse relaxation time in the measurements, ms.
Equation (1) can be utilized to initially delineate the large-scale fracture and small-scale pore-seam systems in shale samples. In addition, the correlation coefficient Ri2 mutation point of lg(Svi) and lg(T2i) under different lateral relaxation times can be used to distinguish the fluid distribution pores furtherly,
(Eq. 2)
where Dj' is the correlation coefficient between lg(Svi) and lg(T2i) at T2i, j=1, 2, with 1 representing the small-scale pore-fracture system and 2 representing the large-scale fracture; is the correlation coefficient between lg(T2i+1) and lg(Svi+1) under the transverse chilling time T2i+1.
Combined with Eqs. (1) and (2), the types of fluid distribution pores in shale can be distinguished, and the differences of saturated oil in various types of pore-fracture system can be quantitatively characterized.
Comment 7:
7.1 Revise the same!
7.2 Define it.
7.3 Allocate these peak behavior.
7.4 Grammar is not there, so kindly double check.
7.5 Ignore it and stick with "to"
7.6 Lack of an article.
7.7 Which software did you use to create these figures?
7.8 What is the scientific concept behind it?
7.9 Why?
7.10 Elaborate on this!
7.11 which two?
7.12 Elaborate on this kind of pressure!
7.13 Check your grammar.
These contents should be modified in 3.2 Shale Oil Saturation Characteristics section.
Response to comments 7: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
3.2. Shale Oil Saturation Characteristics
Shale itself contains a certain amount of organic matter, and the dry core also shows a more pronounced NMR signal intensity. The NMR T2 spectrum of the dry shale core shows an obvious double-peak pattern, the left peak (T2 < 2 ms) is extremely developed, while the right peak (T2 > 2 ms) has a small distribution range and weak signal intensity, which is a typical NMR T2 spectrum characteristic of shale. The left peak of the NMR T2 spectrum represents smaller-sized pores in the shale, indicating that the shale is tight, while the right peak indicates that there are a certain number of microfractures in the shale [36,37]. The layer fractures were sharply saturated by the n-dodecane hydrocarbons at the initial 2 days as shown in Figure 3, and the signal intensity of the left peak features continuous increase with the increasing of the saturation time, especially at the initial 4 days. Subsequently, it features slowly increase, and it tends to be stable after 14 days of saturation (Figure 3).
(a) SS-1 (b) SS-2
Figure 3. The NMR T2 spectrums of shale samples under various saturated times
During the process of shale core saturation with n-dodecane hydrocarbons using a high temperature and high pressure containment device, the n-dodecane hydrocarbons entering the core can be regarded as movable hydrocarbons in shale. To effectively calculate the amount of movable hydrocarbons in shale at different saturation times, the concept of liquid hydrocarbon saturation is proposed in this study to quantitatively characterize it,
(Eq. 3)
where S is the liquid hydrocarbon saturation, %; Si is the shale NMR T2 spectral area at day i of saturation, i=2, 4, 6, 8, 10, 12, 14, dimensionless; Sd is the shale dry core NMR T2 spectral area, dimensionless.
In addition, to quantitatively characterize the differences in the degree of n-dodecane hydrocarbon saturation at different saturation times, the concept of liquid hydrocarbon saturation degree was used to characterize it,
(Eq. 4)
where η is the degree of liquid hydrocarbon saturation, %; Si+1 is the shale NMR T2 spectral area at day i+1 of saturation, i=2, 4, 6, 8, 10, 12, 14, dimensionless; Si is the shale NMR T2 spectral area at day i of saturation, dimensionless.
(a) SS-1 (b) SS-2
Figure 4. The S and η of shale samples under various saturated times
The liquid hydrocarbon saturation of SS-1 and SS-2 shale samples showed an obvious three-stage structure with the continuation of the saturation time. The liquid hydrocarbon saturation showed a rapid increase in the first 4 d of n-dodecane hydrocarbon saturation, then the liquid hydrocarbon saturation showed a slow increase, and after the liquid hydrocarbon saturation time of more than 10 d showed a rapid increase in the liquid hydrocarbon saturation, and the SS-1 and SS-2 shale samples were finally saturated with 26.92% and 31.46% of the liquid hydrocarbon saturation, respectively. The SS-1 and SS-2 shale-type shale samples showed high liquid hydrocarbon saturation, while the absolute amount of liquid hydrocarbons was still low considering the low porosity of the shale. As for the liquid hydrocarbon saturation degree, it shows significantly V-shape, which is similar to the liquid hydrocarbon saturation degree (Figure 4).
Comment 8:
8.1 What is the characteristics of this porous media?
8.2 Which reservoir?
8.3 Be specific.
These contents should be modified in 3.3 Fluid Distribution Pore Division section.
Response to comments 8: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
3.3. Fluid Distribution Pore Division
The pore structure of porous media features fractal characteristics, with the pore fractal dimension D = 2 as the boundary, combined with Eq. (1), the fluid distribution pores in the shale samples can first be divided into two major categories (Figure 5(a1), Figure 5(a2)), larger-size fracture systems and smaller-size pore systems. With Eq. (2) and Eq. (3), the larger-size fractures and smaller-size pores can be further finely divided to obtain the lateral relaxation times corresponding to different types of pore seams (Figure 5). It can be found that the pores with smaller apertures can be divided into external three types under various T2 values (Figure 5(b1), Figure 5(b2)); however, the larger-size fracture systems feature more simple (Figure 5(c1), Figure 5(c2)).
(a) SS-1 (b) SS-2
Figure 5. The classification procedures of fluid distribution pores in shale samples
Based on the enhanced classification of fluid distribution pores, the transverse relaxation time corresponding to larger-sized fractures in SS-1 and SS-2 are T2 ≥ 222.19469 ms and T2 ≥ 222.19470 ms, respectively, and there is no significant difference in the transverse relaxation time corresponding to larger-sized fractures in the shale-type shales. Further, the refined division of smaller-sized pore-fracture systems shows that SS-1 and SS-2 shale samples can be further distinguished into three different types, with the lateral relaxation times corresponding to the fine division of fluid-distributed pores in SS-1 shale samples being T2 = 0.021711 ms and T2 = 3.570786 ms, respectively, and those corresponding to fluid-distributed pores in SS-2 shale samples being T2 = 0.020022 ms and T2 = 4.198707 ms, respectively (Figure 5).
Based on the classification of fluid distribution pores in two shale samples, SS-1 and SS-2, four different types of fluid distribution pores in shale were distinguished. Larger-sized fractures correspond to layer fractures in shale, while smaller-sized pore-seam systems can be distinguished mainly as seepage fractures, micropores, and adsorption pores (Figure 6). Layer fractures are larger in size, and fluids in layer fractures are mainly free-flowing by gravity; seepage fractures are inorganic and organic fractures in shale, which can flow to a certain extent by overcoming capillary forces under certain external stresses; fluids in micropores are more comfortable with capillary forces, and fluids in adsorbent pores are almost immovable. Comparing SS-1 and SS-2 shale samples, it can be found that liquid hydrocarbons are mainly stored in micropores and seepage fractures, and micropores are the main storage space for liquid hydrocarbons; the number of layer fractures and adsorption pores is less, and the amount of liquid hydrocarbons that can be stored in them is also less (Figure 6).
(a) SS-1 (b) SS-2
Figure 6. The types of pores and fractures in the shale samples
Comment 9:
9.1 Indicate some values to see the difference.
9.2 Elaborate on typical!
9.3 Revise the highlights, use proper tense with the proper terminologies.
9.4 Elaborate on the highlight. Because in nature resides in different layers at the subsurface, however 9.5 shale formation is a problematic!
9.6 Generally speaking there are only 2-types of reservoirs SS AND LS and shale exists in both, elaborate on this.
9.7 Kindly revise in whole grammatically.
These contents should be modified in 3.4 Fluid Distribution Pore Division section and 3.5 Implications of Fluid Saturation for Shale Oil Production section.
Response to comments 9: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
3.4. Characteristics of Fluid Differential Saturation in Different Types of Pore Spaces
Based on the pore type division of fluid distribution in shale samples, fluid differential saturation characteristics in four different types of pores, including adsorption pores, micropores, seepage fractures and layer fractures, were characterized with the help of Eq. (3).
Overall, the differential saturation of liquid hydrocarbons in pore-fracture system can be roughly categorized into three types. Type I, the liquid hydrocarbons distributed in the layer fractures. The layer fractures are the fractures features as centimeter level, the fluid in this part of spaces is weakly influenced by the capillary force. In contrary, it is more likely affected by the change of external stress. Therefore, the mobility of shale oil in the layer fractures features as fluctuant (Figure 7(d1), Figure 7(d2)). Type II is represented by liquid hydrocarbons in adsorption pores and seepage fractures, and the saturation characteristics of liquid hydrocarbons in these two types of storage spaces feature as V-shape (Figure 7(a1), Figure 7(a2), Figure 7(c1), Figure 7(c2)), reflecting the dynamic equilibrium between capillary force and external stress. The seepage fractures in SS-2 shale sample is much more developed than that in SS-1 shale sample, and the retention effect of capillary force features stronger than that of the external stress on liquid hydrocarbon. Therefore, SS-2 sample needs a longer time to achieve equilibrium (Figure 7(c1), Figure 7(c2)). The adsorption pores showed strong retention of liquid hydrocarbons for SS-1 and SS-2 shale samples (Figure 7(a1), Figure 7(a2)). Type III is the fluid distributed in the micropores, which features the smaller pore aperture. As the main storage space for liquid hydrocarbon, the saturation of liquid hydrocarbon shows a continuous increase (Figure 7(b1), Figure 7(b2).
Micropores and seepage fractures are the dominant fluid-rich spaces in the shale, and it finally determines the fluid saturation degree. Fluid saturation in micropores shows a trend of steady increase. However, that in seepage seams shows an overall V-shape, which can be divided into three different stages according to the various saturation rates, rapid saturation stage, adjustment stage, and post-adjustment growth stage respectively. For SS-1 shale sample, the shale oil saturation in the micropores increases steadily from 55.97 % in the 4th day to 63.54 % in the 10th day, and it increases rapidly to 76.15 % until saturation (Fig. 8(a)). As a comparison, the shale oil saturation in the micropores of the SS-2 shale sample reaches to 67.29 % in the initial 4 days, and then basically reaches to 82.77 % at the 8th day (Fig. 8(b)). It can be found that the saturation of shale oil in the micropores of SS-2 shale sample is significantly better than that of SS-1 shale sample, and the saturation of shale oil in the micropores of SS-1 and SS-2 shale samples are both V-shaped. The saturation of shale oil in the seepage fractures of SS-1 shale sample at the 4th day is only 70.05 % (Fig. 8(a)), and that for SS-2 shale sample is 92.48% (Fig. 8(b)). However, the oil saturation for microfractures in SS-2 shale sample is negative at 10th day, which may be related to the shale oil discharged from microfractures to the layer fractures in the shale.
(a) SS-1 (b) SS-2
Figure 7. The differences of S in various types of pores and fractures in the shale samples
(a) SS-1 (b) SS-2
Figure 8. The saturation degree differences in micropores and seepage fractures of the shale samples
3.5. Implications of Fluid Saturation for Shale Oil Production
The shale-type shale is developed in the Chang 7 Member of the Ordos Basin, and the resource of shale oil is also abundant. However, the content of brittle minerals (such as quartz, feldspar, calcite, and so on) in the shale reservoir is low, and the shale oil in the shale matrix after fracturing relies on spontaneous imbibition to be continuously discharged outward under the formation temperature and pressure conditions, and its discharge characteristics determine the oil production efficiency of the shale reservoir.
In this study, the saturated procedures of liquid hydrocarbon in the shale can be regarded as the reverse procedures of spontaneous imbibition for shale oil. During the initial period of the spontaneous imbibition of shale oil, the shale oil in the layer fractures could be discharged sharply, and it features fluctuant. However, the shale oil in the seepage fractures present decrease sharply in the initial period, and it tends to be stable with the increased time. This is mainly due to the resistance of the capillary force, and it features as the self-adjustment. The discharge of shale oil in micropores is mainly affected by the capillary force, and it presents stable. As for the discharge of shale oil in the adsorption pores, it is similar for that in the seepage fractures. However, it should be noticed that the quantity of shale oil in the adsorption pores is less, and the contribution of the shale oil movability can be ignored. As the dominant storage spaces in the shale-type shale, the movability of shale oil in micropores and seepage fractures would finally determine the shale oil movability. It can be found that movability of shale oil features contrary in the micropores and seepage fractures, and the existence of seepage seams can enhance the shale oil movable degree. Therefore, it would become an important research direction to transform part of the micropores into seepage fractures, which can be utilized to increase the mobility of shale oil in shale-type shale.
Comment 10: Revise the highlight scientifically and grammatically. This contents should be modified in Conclusions section.
Response to comments 10: Thanks very much for your comments. All of the mistakes and unclear expressions are modified, and the modified content is as follow,
The fluid distribution pores in shale-type shale can be classified into four types, adsorption pores, micropores, seepage fractures and layer fractures respectively, and the micropores and seepage fractures are the dominant storage spaces for the liquid hydrocarbon in shale-type shale.
Special thanks for your comments and suggestions.
Author Response File: Author Response.pdf
Reviewer 3 Report
Comments and Suggestions for AuthorsLi et al. present a well-written and organized study delving into the hydrocarbon saturation characteristics within two samples of oil shale from the Chang 7 reservoir. The findings of this study are backed by the results, and I suggest it for publication in Processes after a minor revision. My primary critique is that more care should be placed in the presentation of the figures and tables, especially in explaining the content in the captions. I have some other concerns below:
Minor Concerns:
[Table 1] This table is confusing, I suggest reformatting it. Instead of micrometers to the negative three, perhaps nanometers would be more appropriate.
[Figure 1] The caption needs to be more specific about the sample tested.
[Figure 2] Again, you need to be more specific about what is being shown.
[Figure 4] It would be nice if the resolution of this figure could be improved.
[Figure 7] It is challenging to read the y-axis labels in this figure. Please consider increasing the font size.
Major Concerns:
[Figure 5] I cannot discern what this figure is trying to show. Please be explicit in the text and provide an expanded figure caption.
[Micropores and seepage fractures] Is it possible to quantitatively compare the two sample results rather than qualitatively only?
[Sample selection] Please explain why you used only one of the three types of shales present in the Chang 7.
Language Concerns:
[Last paragraph of introduction] “were took” should be “were taken.”
[First paragraph in 3.4] “space” should be “spaces.”
Author Response
Comment 1: [Table 1] This table is confusing, I suggest reformatting it. Instead of micrometers to the negative three, perhaps nanometers would be more appropriate.
Response to comment 1: Thanks very much for your comments and suggestions. We are so sorry for the confusing tale in the original manuscript. Table 1 shows the basic properties parameters of the shale samples, porosity, permeability and inorganic minerals content respectively. Now, we have modified table 1 into three different part, which we hope it can feature the parameters clearly. As for the unit of permeability, 10-3μm2 is a SI of permeability, so we do not modify it in the revised manuscript. The modified table 1 is showed as follow,
Table 1. The properties parameters of the shale samples
|
Properties parameters |
Shale samples |
||
|
SS-1 |
SS-2 |
||
|
Porosity (%) |
0.99 |
1.01 |
|
|
Permeability (×10-3μm2) |
0.1231 |
0.1661 |
|
|
Inorganic minerals content (%) |
Quartz |
25.40 |
24.40 |
|
Potassium feldspar |
6.30 |
2.60 |
|
|
Plagioclase feldspar |
27.90 |
27.70 |
|
|
Calcite |
0.40 |
/ |
|
|
Dolomite |
0.60 |
/ |
|
|
Pyrite |
/ |
0.60 |
|
|
Muscovitize |
/ |
3.40 |
|
|
Clay minerals |
39.40 |
41.30 |
|
|
I/S |
36.20 |
27.00 |
|
|
It |
15.50 |
19.20 |
|
|
Kao |
18.50 |
18.80 |
|
|
C |
29.80 |
35.00 |
|
Note: I/S is the illite/smectite formation; It is the illite; Kao is the kaolinite; and C is the chlorite.
Comment 2: [Figure 1] The caption needs to be more specific about the sample tested.
Response to comment 2: Thanks very much for your comments. We have modified the caption of Figure 1, and the resolution is also improved, which we hope can reach to your approval. The modified figure 1 is showed as follow,
Figure 1. The NMR spectrums under various values of SW, PRG, TW, NS and NECH for shale sample
Comment 3: [Figure 2] Again, you need to be more specific about what is being shown.
Response to comment 3: Thanks very much for your comments. We have modified the caption of Figure 2, and the resolution is also improved, which we hope can reach to your approval. The modified figure 2 is showed as follow,
Figure 2. The various types of pores and fractures in the shale sample
((a) clay mineral intergranular pores and intraparticle microfractures; (b) the fractures developed in the edges of the inorganic and organic matter; (c) intraparticle microfractures; (d) organic matter pores)
Comment 4: [Figure 4] It would be nice if the resolution of this figure could be improved.
Response to comment 4: Thanks very much for your comments. We have improved the resolution of figure 4 to 600 dpi with a tiff format, which we hope can reach to your approval. The modified figure 4 is showed as follow,
Figure 4. The S and η of shale samples under various saturated times
Comment 5: [Figure 7] It is challenging to read the y-axis labels in this figure. Please consider increasing the font size.
Response to comment 5: Thanks very much for your comments. We have increased the font size to 24pt, which we hope can reach to your approval. The modified figure 7 is showed as follow,
Figure 7. The differences of S in various types of pores and fractures in the shale samples
Comment 6: [Figure 5] I cannot discern what this figure is trying to show. Please be explicit in the text and provide an expanded figure caption.
Response to comment 6: Thanks very much for your comments. Figure 5 shows the whole procedures to classify the various types of pores and fractures in the shale sample. Firstly, the pore and fracture system in the shale was divided into two types, larger fractures and smaller pore-fractures, then with the parameter Dj’, the pores and fractures with smaller apertures were divided three types furtherly. In order to state it more clearly, we have added the relative content in this part, and the modified contents are as follow,
The pore structure of porous media features fractal characteristics, with the pore fractal dimension D = 2 as the boundary, combined with Eq. (1), the fluid distribution pores in the shale samples can first be divided into two major categories (Figure 5(a1), Figure 5(a2)), larger-size fracture systems and smaller-size pore systems. With Eq. (2) and Eq. (3), the larger-size fractures and smaller-size pores can be further finely divided to obtain the lateral relaxation times corresponding to different types of pore seams (Figure 5). It can be found that the pores with smaller apertures can be divided into external three types under various T2 values (Figure 5(b1), Figure 5(b2)); however, the larger-size fracture systems feature more simple (Figure 5(c1), Figure 5(c2)).
(a) SS-1 (b) SS-2
Figure 5. The classification procedures of fluid distribution pores in shale samples
Comment 7: [Micropores and seepage fractures] Is it possible to quantitatively compare the two sample results rather than qualitatively only?
Response to comment 7: Thanks very much for your comments. The qualitatively compare of the difference saturated oil characteristics for micropores and seepage fractures in the shale samples were added, and the modified contents are as follows,
Micropores and seepage fractures are the dominant fluid-rich spaces in the shale, and it finally determines the fluid saturation degree. Fluid saturation in micropores shows a trend of steady increase. However, that in seepage seams shows an overall V-shape, which can be divided into three different stages according to the various saturation rates, rapid saturation stage, adjustment stage, and post-adjustment growth stage respectively. For SS-1 shale sample, the shale oil saturation in the micropores increases steadily from 55.97 % in the 4th day to 63.54 % in the 10th day, and it increases rapidly to 76.15 % until saturation (Fig. 8(a)). As a comparison, the shale oil saturation in the micropores of the SS-2 shale sample reaches to 67.29 % in the initial 4 days, and then basically reaches to 82.77 % at the 8th day (Fig. 8(b)). It can be found that the saturation of shale oil in the micropores of SS-2 shale sample is significantly better than that of SS-1 shale sample, and the saturation of shale oil in the micropores of SS-1 and SS-2 shale samples are both V-shaped. The saturation of shale oil in the seepage fractures of SS-1 shale sample at the 4th day is only 70.05 % (Fig. 8(a)), and that for SS-2 shale sample is 92.48% (Fig. 8(b)). However, the oil saturation for microfractures in SS-2 shale sample is negative at 10th day, which may be related to the shale oil discharged from microfractures to the layer fractures in the shale.
(a) SS-1 (b) SS-2
Figure 8. The saturation degree differences in micropores and seepage fractures of the shale samples
Comment 8: [Sample selection] Please explain why you used only one of the three types of shales present in the Chang 7.
Response to comment 8: Thanks very much for your comments. There are three different types of shale in the Chang 7 Member, shale-type shale, textured shale and interbedded shale, as for the textured shale and the interbedded shale, the content of slit-sandstone is higher than that of shale-type shale, and the saturated oil characteristics is similar to the slit-sandstone. Besides, the development of textured shale and interbedded shale has enter into commercialize step by step, while that for the shale-type shale features at the initial stage. Therefore, with an accurate understanding of the saturated oil characteristics of shale-type shale would help us to know more about the development of shale-type shale oil.
Comment 9: [Last paragraph of introduction] “were took” should be “were taken.”
Response to comment 9: Thanks very much for your comments and suggestions. This mistake has been modified, and the modified contents were highlighted in the revised manuscript.
Comment 10: [First paragraph in 3.4] “space” should be “spaces.”
Response to comment 10: Thanks very much for your comments and suggestions. This mistake has been modified, and the modified contents were highlighted in the revised manuscript.
Special thanks for your comments and suggestions.
Author Response File: Author Response.pdf
Round 2
Reviewer 1 Report
Comments and Suggestions for AuthorsNA
