Experimental study on reservoir characteristics and oil-bearing properties of Chang 7 lacustrine oil shale in Yan’an area, China

2.1 Samples and experiments

The experimental samples in this study were collected from the Chang 7 Member of the Upper Triassic Yanchang formation in the Yan’an area of the Ordos basin (Figure 1). Experimental test items include argon ion polishing-scanning electron microscope, geochemical tests (total organic carbon (TOC), S ₁, S ₂, T _max, chloroform pitch “A”), high-pressure mercury intrusion, nitrogen and carbon dioxide adsorptions, and nuclear magnetic resonance. Argon ion polishing-scanning electron microscope was completed by the Suzhou Institute of Nanotechnology and Nano Bionics, Chinese Academy of Sciences, and the ion polishing equipment was a Gantan693 SEM sample cross-section polishing device. A Carl Zeiss Merlin Microscope Workstation scanning electron microscope (FE-SEM) was used to observe the internal minerals and pore structures of the shale. The resolution of the microscope in the transmission electron detection mode is 0.6 nm (15 keV).

Figure 1

Location, stratigraphic unit histogram, and structure of the study area. Notes: (a) the study area is located in the Yan’an area of the Ordos basin, (b) division of stratigraphic units and sedimentary facies of the Upper Triassic Yanchang formation in the study area, and (c) structure and well location distribution of Chang 7 Member in the study area.

The TOC content was completed in the North China Petroleum Exploration and Development Research Institute, and the instrument was the LECO CS844 infrared carbon and sulfur analyzer, LECO Corporation Shanghai Representation. Moreover, a YQ-VIIA oil and gas display evaluation instrument was used to measure the S ₁ and S ₂ content of the source rock and the maximum cracking temperature T _max. A fast solvent extraction instrument ASE300, DIONEX Corporation Shanghai Representation was used to measure the chloroform pitch “A.”

High-pressure mercury injection and nitrogen and carbon dioxide adsorption experiments were completed in the Beijing Physics and Chemistry Center Laboratory. The instrument used for high-pressure mercury intrusion was a fully automatic mercury intrusion meter (PoreMasterGT 60, Quantachrome Corporation Shanghai Representation). The nitrogen adsorption tests were completed with the ASAP2020 specific surface and porosity analyzer, micromeritics Corporation Beijing Representation. In addition, the test temperature was −195.8°C, the test pressure (P/P ₀) was 0.009–0.998, and the BJH model was used to interpret the adsorption data to obtain pore size distribution data of 2–300 nm. A NOVA4200e specific surface area porosity analyzer, Nanjing Weimet Scientific Instrument Co., LTD; was used for the carbon dioxide adsorption tests. The test temperature was 0°C, the test pressure (P/P ₀) was less than 0.03, and the nonlocal density functional theory model was used to interpret the adsorption data to obtain pore size distribution data below 2 nm.

A SPEC-PMR-20M nuclear magnetic resonance instrument, Beijing SPEC Technology Development Co., LTD; was used for nuclear magnetic resonance testing of shale samples, with a magnetic field frequency of 20 M. For SEM image gray-scale correction, Image-pro Plus Software, Quantachrome Corporation Shanghai Representation; was used to extract the pore structure parameters in the two-dimensional images, such as face ratio and pore diameter. Considering the influence of image magnifications on the results of pore identifications, two-dimensional images with the same magnification were used in the study to observe and count the pore structure parameters.

2.2 Movable oil identification and aperture conversion

The main hydrogen-containing components in shale rocks include water, liquid hydrocarbons, gaseous hydrocarbons, solid and semisolid organic matter (pitch, kerogen, etc.), crystal water of clay minerals, and structured water. The relaxation mechanisms of different hydrogen-containing components in rocks are very different. Based on this difference, the longitudinal relaxation time T ₁ can be introduced, and the T ₁–T ₂ two-dimensional spectrum can be obtained. To use the T ₁–T ₂ two-dimensional spectrum to characterize the fluid content, it is necessary to first explore the response law of the samples in the study area on the spectrum, and then find the signal area of each component and build a chart. In the T ₁–T ₂ spectrum of the saturated water state, the signals of movable oil and free water overlap in a large range on the T ₂ coordinate. The minimum T ₂ of the T ₁–T ₂ spectrum is about 1 ms, and the mass signal area of 1 ms < T ₂; T ₁/T ₂ >10 ms is movable oil. T ₂ of free water is slightly longer, 1 ms < T ₂, T ₁/T ₂ is a long signal area between 1 and 10. Solid organic matter and clay water are in the T ₂ < 1 ms zone.

The T ₂ relaxation time and the pore size distribution obey a certain functional relationship. The conversion coefficient C was determined by the pore shape and the relaxation rate of the pore surface. The pores developed in the macro shale samples are rich and diverse, and the shape factor F _s of a single pore shape cannot be used to calculate the conversion parameters. Therefore, the conversion coefficient C cannot be obtained directly, but it can be obtained by regression fitting between the corresponding T ₂ and the aperture r. First, the T ₂ spectrum is differentiated to obtain the differential distribution curve of signal amount and T ₂, and its meaning is consistent with the pore size distribution curve. However, the absolute value of the T ₂ spectrum and the pore size distribution curve are not comparable. To compare the shape of the two curves more intuitively, after the differentiated T ₂ spectrum is obtained, they are standardized with their maximum value as 100%, respectively. Furthermore, the relative differential T ₂ spectrum and pore volume distribution curve, and their corresponding T ₂ and D can be obtained. By comparing the T ₂ spectra and pore size distribution curves of different samples, the T ₂–D mapping results were obtained:

Furthermore, the correlation analysis between iron-containing materials such as pyrite, TOC, and clay minerals, and C and p values of different shale samples were performed, respectively. The calculated relationship between the fitted pyrite content and C and p was used to obtain the C and p values of the test sample. Then, the T ₂ spectra of different experimental fluids were converted into pore size distributions.

3.1 Mineral composition and content

The lacustrine shale is an important field of “searching for oil from the source.” Shale reservoirs have both source and storage attributes [26–28]. The Chang 7 shale of the Yanchang formation in the Ordos basin was formed in a shallow lake-deep lake sedimentary background, buried at a depth of 1,300–1,500 m, and has strong heterogeneity. The lithologies of the Chang 7 Member include dark mudstone, carbonaceous mudstone, siltstone, silty mudstone, and argillaceous siltstone. Among them, the laminar structures are usually developed in siltstones (Figure 2). The cumulative thickness of the silty laminae that can be recognized by the naked eye accounts for 5–26% of the total shale thickness, and the frequencies of the silty laminae are between 5 and 24 layers/m. The extension distance of sandy laminae in shale varies greatly. The contents of clay minerals in the Chang 7 shale range from 21 to 65%, with an average of 46.71%; the clay minerals are mainly composed of eamon mixed layer and illite, and their contents account for 62.0–94.0% of the total clay mineral contents, and the average value is 81%. For other types of clay minerals, the average contents of chlorite and kaolinite are 18 and 13%, respectively. Moreover, the contents of quartz and feldspar in the shale samples range from 11.4 to 48% (average of 27.77%) and 2 to 38.2% (average of 16.83%). The carbonate components include siderite and calcite, and their contents range from 0 to 38.37%, with an average value of 5.89%. In addition, the contents of pyrite components representing the strongly reducing sedimentary environment range from 0 to 22%, with an average value of 2.53% (Table 1).

Figure 2

Comprehensive histogram (left) and lithology images (right) of the Chang 7 Member of the Yanchang formation in Well YY22 in the study area.

Compared with strong brittle marine shale, Chang 7 lacustrine shale has typical “plasticity” characteristics. The average content of brittle minerals (quartz + feldspar + pyrite) is 31.24%, which is significantly lower than the brittle mineral content (61.3–69.5%) of the marine shale in southern China. Meanwhile, the average clay mineral content of Chang 7 shale is 58.14%. Figure 2 shows that the geochemical parameters of the shale at different depths in the same well are quite different, reflecting the strong heterogeneity of lacustrine shale.

3.2 Organic geochemical parameters

According to observations under the microscope, the organic matter in the Chang 7 shale came from lower organisms. The occurrence forms of organic matter include gas/liquid hydrocarbons and solid organic matter [29–31]. Among them, solid organic matter can be further divided into sedimentary organic matter (kerogen) and transported solid organic matter [11,32]. The organic matter components mainly exist in the shale in bedding and dispersed distribution forms. In some places with large clastic particles, in the pores of fossil cavities, and pyrite aggregates, organic matter exists in the shale in the form of bitumen [12,33,34]. Laminar organic matter is usually parallel or nearly parallel to the shale bedding, and its distribution is mostly continuous or intermittent in the form of strips, waves, spindles, filaments or laminae.

The kerogen types of Chang 7 shale include Type II₁ and a small amount of Type II₂; hence, kerogen has the dual characteristics of sapropel type and mixed type. The TOC contents in shale range from 0.13 to 24.3%, with most values ranging from 2 to 8%, and the average value is 4.69%. The TOC content of Chang 7 shale is significantly higher than that of marine shale (1.04–5.89%) [35]. In addition, the vitrinite reflectances (R ₀) of the Chang 7 shale range from 0.8 to 1.1%; the T _max values range from 421°C to 467°C, with a peak value of 450°C–455°C, and an average value of 450°C. According to analysis, the Chang 7 shale is a high-quality source rock, which is in the mature-wet gas (oil-associated gas) stage, and organic matter has a strong hydrocarbon-generating ability. Some shale even generates oil-type gas from initial thermal cracking. As a result, oil wells in some areas have large associated gas production, and even shale gas wells with large gas volume. However, in general, the thermal evolution degree of lacustrine shale is lower than that of marine shale (R ₀ > 2.5%).

3.3 Pore types

Through the observations of a large number of thin sections under the microscope, the types of pores developed in the Chang 7 formation rocks include intergranular pores, intragranular pores, organic pores, and microcracks. In the study, Image-pro Plus image analysis software was used to extract the face ratios and pore diameters in the two-dimensional images.

3.3.1 Intergranular pores

The intergranular pores in the Chang 7 shale are the residual intergranular pores developed between the clastic particles and the pores between the clay minerals and the clastic particles (Figure 3a). Furthermore, the edges of some intergranular pores were eroded into dissolution enlarged pores. There are also a small amount of intercrystalline or intergranular pores developed in calcite cements and quartz (Figure 3b). The pore diameters of the intergranular pores are between 5 and 600 nm, with a maximum of 3.4 µm; the pore diameters of most pores are less than 200 nm, with an average of 75 nm (Figure 4a). Intergranular pores with a pore diameter of less than 50 nm accounted for 52%, microporous-level intergranular pores with a pore diameter between 50 and 100 nm accounted for 30%, and intergranular pores with a pore diameter greater than 100 nm accounted for 17%.

Figure 3

Microscopic characteristics of pores in different types of rocks in Chang 7 shale. Notes: (a) intergranular pores in siltstone, Well YY1, single polarized light, 1,355 m; (b) intergranular pores between clastic particles, Well YY4, SEM, 1,528 m; (c) intergranular pores, SEM, Well YY8, 1522.8 m; (d) intragranular dissolution pores, SEM, Well YY8, 1522.8 m; (e) intragranular pores of clay mineral aggregates, SEM, Well YY7, 1140.1 m; (f) intragranular pores of pyrite aggregates, SEM, Well YY22, 1299.73 m; (g) organic matter filled between clastic particles (organic pores developed), SEM, Well YY22, 1307.32 m; (h) organic pores in kerogen, SEM, Well YY11, 1378.37 m; and (i) laminate structure and bedding microfractures, cross-polarized light, Well YY11, 1378.37 m.

Figure 4

Pore size distribution and CT scan characteristics of various pores in shale. Notes: (a) frequency distribution of pore diameters of different types of pores; (b) coupling of organic pores (green) and inorganic pores (red), FY2 shale sample (quartz 18.5%, plagioclase 10.5%, calcite 4.1%, illite 57.1%, chlorite 8%, and pyrite 1.8%), 1269.51 m.

3.4 Pore structures

Microscale to nanoscale pores are developed in shale reservoirs, and it is difficult to test the full-scale pore size of shale with a single experimental method [35,36]. In this study, mercury intrusion method was used to characterize microscale pores in shale, while high-resolution FE-SEM. The porometer used in the mercury intrusion experiment was a Quan-tachrome PoreMasterGT 60. Nitrogen and carbon dioxide adsorptions were used to characterize nanoscale pores in shale. The test equipment was a Quadrasorb SI pore analyzer, Quantachrome Corporation Shanghai Representation. The rock types selected in this study include pure shale (with undeveloped siltylaminae), shale with developed siltylaminae (lamellar shale), and siltstone. The experimental samples were obtained from the Fuxian area of Yan’an. The Chang 7 member of this area belongs to the deep lake–semi-deep lake facies, and its lithology is black shale as a whole. The semi-deep lacustrine shale in the northeast of the study area contains limited sandy interbeds. The pore size data of black shale is difficult to obtain by mercury intrusion method. Different methods were applied to different samples in this study. The mercury injection method was mainly applied to sandy interlayer samples. Sandy interbeds are mostly argillaceous siltstone, which is denser than conventional sandstone. Therefore, it is difficult to reach the level of pore development above the mesopore level of conventional sandstone, and its effective pore structure information is mainly distributed in 50–100 nm. In the end, affected by the development scale and quality of sandy interlayers, the total volume of medium and large pores is relatively small.

According to the characteristics of the pore size distribution curve, the common feature of shale and siltstone is that the micropores and some mesopores with small pore diameters (2–5 nm) have high peaks but small enclosed areas (Figure 5). These pores are developed in large numbers but provide small pore volumes. As the pore size increases, the overall pore size distribution curve shows a downward trend; although the number of medium-large pores is small, it provides the main pore space (Figure 5). The differences in pore size distribution between siltstone and shale is mainly reflected in the pore size range of 5–100 nm. It can be seen that the pore size distribution curve of shale showed a rapid or slow downward trend (Figure 5a), whereas the siltstone had a gentle convex shape, and its peak was more inclined to larger pores than shale (Figure 5b). The pores in siltstone with a pore size greater than 100 nm are more developed than shale (Figure 5b and c). However, it has no obvious advantages compared with the adjacent silty-laminated shale (Figure 6a and c).The differences in pore size distribution between shale and silty laminar shale are mainly reflected in the large pores with a pore size of 100 nm to 1 µm. The pores in this interval are obviously more developed in the silty laminar shale (Figures 5a and b and 6a and b), and the pore volumes are also larger (Figure 6a–c).

Figure 5

Full-scale pore size distribution of different types of rocks in Chang 7 Member of YY22 well. Notes: (a) silty laminar shale (quartz 32.5%, plagioclase 15.6%, calcite 5.1%, illite 32.3%, chlorite 7%, pyrite 5.8%, and kaolinite 1.7%); (b) pure shale (without siltylaminae) (quartz 15.5%, plagioclase 5.5%, calcite 3.1%, illite 65.1%, chlorite 8.1%, and kaolinite 2.7%); (c) siltstone (quartz 40.1%, plagioclase 20.3%, calcite 10.1%, illite 17.5%, chlorite 4%, and pyrite 8%).

Figure 6

Pore volume distribution of different types of rocks in the Chang 7 Member of Well YY22. Notes: (a) silty laminar shale; (b) pure shale (without silty laminae); (c) siltstone.

Nuclear magnetic resonance experiments showed that the nuclear magnetic resonance (NMR) T ₂ spectrum of laminar shale includes multipeak type, right-side single-peak type, and left-side single-peak type. Laminar shale had a slightly higher degree of micropore development than siltstone (Figure 6a), with micropores accounting for 6.4%, mesopores accounting for 60.0%, and macropores accounting for 33.6%. However, the NMR T ₂ spectrums of shale with underdeveloped lamellae were dominated by multipeak and right-side single-peak. The micropores are relatively developed, accounting for 29.4%, mesopores accounting for 56.3%, and large pores accounting for 25.9% (Figure 6b). For the siltstone interlayers, the medium and large pores were relatively developed (Figure 6c), the medium and large pores accounted for 44.9 and 55.2%, respectively, and the average micropore volume ratio was 3.8%.

3.5 Petrophysical properties

To further compare the differences in petrophysical properties of pure shale, laminar shale, and siltstone, in this study, helium gas expansion method and pulse attenuation method were used for the tests of total porosity and permeability of the three types of samples. The results showed that the porosity of pure shale ranged from 1.10 to 6.33%, with an average of 3.57%, and the permeability ranged from 0.1 to 10 mD, with an average of 1.3 mD. The porosity of laminar shale ranged from 1.14 to 6.24%, with an average of 4.50%. The permeability range was large, with a minimum of 0.01 mD and a maximum of 38.6 mD, with a span of up to 3 orders of magnitude. The distribution interval of permeability was 0.1–10 mD, and the average permeability was 5.55 mD. The porosity of siltstone ranged from 0.74 to 8.37%, with an average of 3.30%, and the permeability ranged from 0.1 to 10 mD, with an average of 1.3 mD.

The range of porosity (after oil washing) between different lithologies, lithology combinations, and the same lithology varies widely, indicating that the rocks of the Chang 7 Member are strongly heterogeneous. Statistics showed that the average porosities of shale before and after oil washing were 1.78 and 3.02%, respectively; the average porosities of laminar shale before and after oil washing were 2.39 and 3.41%, respectively; and the average porosities of siltstone before and after oil washing were 3.27 and 3.70%, respectively.

4.1 Lower limit of oil-bearing properties of lacustrine oil shale

Based on a large number of microscopic observations, liquid hydrocarbons in shale existed in macropores, mesopores, and micropores. They not only occurred in inorganic pores and cracks, but also in organic pores [37,38]. Comparing the microscopic observation results of the samples before and after washing oil, it can be seen that there were relatively few organic pores in the organic matter, and the pore diameters of the organic pores were small. After oil washing, the number of organic pores increased and the pore diameter changed, indicating that the organic pores were occupied by soluble hydrocarbons. Liquid hydrocarbons were present in organic matter in a free state and in an adsorbed state.

The liquid hydrocarbons in the micropores and some of the mesopores were present in a free state and an adsorbed state [39–41]. However, the free liquid hydrocarbons in the pores with too small pore size were immovable, and this part of the pores was invalid for shale oil. Most of the movable oil in shale was distributed in the range of T ₂ > 1 ms, and the corresponding pore size was greater than 20 nm. Therefore, 20 nm is the lower limit of the effective pore size of the shale oil reservoir in the study area. There are differences in the amount and proportion of movable oil in different rock types. The effective pore volume in the siltstone is relatively large, and the movable oil content is higher, followed by the silty laminar shale, and the pure shale without the siltstone laminar has low movable oil content (Figure 7).

Figure 7

Pore size distribution of movable oil in different types of shale. Notes: (a) quartz 35.6%, plagioclase 19.7%, calcite 13.9%, illite 20.5%, chlorite 4%, and pyrite 6.3%; and (b) quartz 40.1%, plagioclase 20.3%, calcite 10.1%, illite 17.5%, chlorite 4%, and pyrite 8%, laminar siltstone; (c) quartz 30.5%, plagioclase 14.2%, calcite 7.2%, illite 36.8%, chlorite 10%, and kaolinite 1.3%; (d) quartz 32.5%, plagioclase 15.6%, calcite 5.1%, illite 32.3%, chlorite 7%, pyrite 5.8%, and kaolinite 1.7%, laminar shale; (e) quartz 15.5%, plagioclase 5.5%, calcite 3.1%, illite 65.1%, chlorite 8.1%, and kaolinite 2.7% and (f) quartz 10.6%, plagioclase 3.2%, calcite 2.1%, illite 67.1%, chlorite 12.8%, and kaolinite 4.2%), pure shale (without silty laminae). Red data: pore size distribution converted by T ₂ spectrum; brown data: pore size distribution tested by adsorption method.

4.2 Shale oil content

For the pore volume occupied by liquid hydrocarbons, the contents of liquid hydrocarbons in pure shale ranged from 0.36 to 0.77 cm³/100 g, with an average of 0.59 cm³/100 g. The contents of liquid hydrocarbons in siltstone ranged from 0.44 to 0.47 cm³/100 g, with an average of 0.46 cm³/100 g. However, the liquid hydrocarbon contents in silty laminar shale vary widely. Among them, the liquid hydrocarbon contents of No. 22 and No. 31 samples were higher than 0.8 cm³/100 g, whereas the liquid hydrocarbon contents of A4 and A7 samples were less than 0.5 cm³/100 g.

By testing the porosity of samples before and after oil washing, the porosity of liquid hydrocarbons in shale can be obtained. Then, the pore size distribution curves before and after washing oil were obtained by testing the pore structures of the samples before and after the organic solvent was extracted. The pore size distribution curve after organic solvent extraction subtracts the pore size distribution curve ahead of organic solvent extraction, and then the pore size distribution of the pores occupied by shale oil can be obtained. Furthermore, the oil-bearing pores were divided into k intervals, and the oil-bearing pore volume v o k of different pore size intervals was obtained. Similarly, the pore size distribution curve after oil washing was divided into k intervals, and the total pore volume v T k of different pore size intervals was obtained. v o k divided by v T k represents the oil saturation of different aperture intervals. Figure 8 shows the variation of liquid hydrocarbon contents and saturations with pore size in the range of 2–100 nm. As shown in Figure 8a, c and e, the volume of liquid hydrocarbons in shale pores gradually decreases with the increase in pore size, whereas this phenomenon is not obvious in silty laminar shale and siltstone. Especially in the pore size range of 2–40 nm, the volume of liquid hydrocarbons in the pores fluctuates basically at the same level (except for sample No. 31). Figure 8b, d and f are the results of the changes in liquid hydrocarbon saturations with pore size in the test samples. It can be found that in the pore size range of 2–100 nm, the saturations of shale liquid hydrocarbons in the pores gradually decreased as the pore size increased (Figure 8b), and the saturations of liquid hydrocarbons gradually decreases from 58–88 to 19–30%. The liquid hydrocarbon saturations of siltstone were generally less than 50%, and the saturations had a decreasing trend as the pore size increased (Figure 8f). It can be seen from Figure 8d that the saturation distribution characteristics of liquid hydrocarbons in the pores of the silty laminar shale can be divided into two types: one is similar to shale (No. 22 and No. 31 samples). The liquid hydrocarbon saturations were relatively high, and the liquid hydrocarbon saturations gradually decreased as the pore size increased (from 70–92 to 20–52%); the other type is similar to siltstone (No. 4 and No. 7 samples). The saturations of liquid hydrocarbons were low. However, as the saturations of the pore size distribution fluctuated up and down, there was no significant change in the saturations of liquid hydrocarbons.

Figure 8

Liquid hydrocarbon contents and saturations in the pore size range of 2–100 nm and their relationship with pore diameters. Notes: (a and b) pure shale (without laminae), (c and d) silty laminar shale, and (e and f) siltstone.

4.3 Occurrence characteristics of shale oil

Hydrocarbon accumulation in shale belongs to hydrocarbon retention accumulation [42–44]. Pure shale has a high content of clay minerals, whereas rigid clastic particles are small in size and low in content. However, the rigid clastic particles in the silty laminar layer are larger in size and higher in content, and inorganic pores are developed [45–47]. During the burial process of shale reservoirs, organic matter related to sedimentation will form some derivatives in the process of transforming into kerogen [47,48]. Together with the intermediate products in the process of kerogen oil generation, it will migrate to the pores near the kerogen and form a solid pitch through an ultrashort distance. Therefore, it is often distributed in the vicinity of kerogen, but the quantity is limited. Then, some inorganic mineral intergranular and intragranular pores, dissolved feldspar pores, and microcracks will remain in the silty laminae and clay layers (Figure 9a).

Figure 9

Microscopic retention and migration model of shale oil in Chang 7 Member of Yanchang formation. Notes: (a) pore characteristics before shale oil was formed, (b) pore characteristics when shale oil was generated in large quantities, and (c) pore characteristics under current shale oil retention conditions.

As the burial depth and formation temperature increased, the organic matter in the shale began to generate oil [49–51]. Some organic pores were formed in part of the kerogen. When the oil and gas contents exceeded the dissolved expansion and adsorption capacities of kerogen, the excess oil and gas were released from the kerogen, and then migrated to adjacent pores through organic matter-inorganic pores and microcracks (Figure 9b). As the maturity of organic matter increased, more and more oil and gas were generated and released from kerogen. Furthermore, oil and gas migrated from the clay layer through organic matter and organic pores–inorganic pores and microcracks to the silty laminae with relatively coarse grain size, large pore size, and better porosity (Figure 9c). With the further increase of burial depth and formation temperature, compaction and hydrocarbon generation caused the internal pressure of hydrocarbon migration to increase, and some microcracks were formed or reopened. Finally, oil and gas migrated from organic matter and organic pores–inorganic pores and microcracks to fine sandstone reservoirs with greater thickness and better porosity (Figure 9).

4.4 Influencing factors of oil-bearing properties of lacustrine shale

4.4.1 Silty laminae

The siliceous content in shale reservoirs can significantly improve the petrophysical properties of shale. Using the established NMR identification template of solid organic matter and liquid hydrocarbons in shale, the proportion of movable oil in each sample was analyzed (Figure 10). The results showed that the proportion of movable oil in siltstone was relatively high, ranging from 51 to 72.6%. The second is the shale with silty laminae, and the proportion of movable oil was between 39.2 and 56.7%, with an average of 46.9%. However, the proportion of movable oil in shale without silty lamina was relatively low, ranging from 24.2 to 51.9%, with an average of 39.6%.

Figure 10

Statistical results of the movable oil ratios of different types of shale in the Chang 7 Member.

4.4.2 TOC and R ₀

Chloroform bitumen “A” and pyrolysis parameter S ₁ (soluble hydrocarbons) refer to liquid hydrocarbons retained in the shale in a free state and an adsorbed state. Figure 11a and b shows that both the S ₁ content and the chloroform pitch “A” content are positively correlated with TOC. This shows that the organic carbon content is the material basis for shale oil and gas generation and controls the total content of shale oil. However, in some samples, the correlation between the content of chloroform pitch “A” and the content of pyrolysis parameter S ₁ (soluble hydrocarbon) and TOC is relatively poor (Figure 11a). On the one hand, this may be related to the development of inorganic pores in some shale and the occurrence of shale oil in inorganic pores; on the other hand, it is related to the differences in the development degree of organic pores and the ability to adsorb oil of different types of organic matter.

Figure 11

Relationship between the TOC content and the content of thermal simulation geochemical parameters. Notes: (a) S ₁, (b) chloroform pitch “A”, and (c) OSI (oil saturation index (S ₁ × 100/TOC)).

Oil saturation index (S ₁ × 100/TOC, OSI) is an index used to characterize the movable oil content in shale. It can be seen from Figure 10c that there is a negative correlation between the OSI and the organic matter content. This indicated that a considerable amount of shale oil was present in the solid organic matter in a swelled or adsorbed state. The overall correlation between OSI and total organic carbon content of shale reservoirs in different wells was different (Figure 11b). This was related to the degree of silty laminae development, pore types, pore structures, and petrophysical properties of the reservoir.

The evolution of organic matter has a significant effect on the development of shale pores. When the organic matter maturity (R ₀) in shale was less than 0.9%, organic pores were basically undeveloped or have little development; only when the organic matter maturity (R ₀) in shale was greater than 1.1% (Figure 11c), organic pores appeared in large numbers. As the maturity increased, the degree of organic pore development increased as well.

4.4.3 Petrophysical properties

The content of liquid hydrocarbons in pores with different pore sizes and the proportion of pore space occupied by different liquid hydrocarbons are also different [52–56]. The presence of liquid hydrocarbons can be seen even in micropores with a pore diameter of less than 2 nm. They occupy the highest proportion of pore volume, but the total amount of liquid hydrocarbons present in them is lower. The mesopores with a pore diameter of 2–50 nm have the highest content of liquid hydrocarbons. The liquid hydrocarbon content in the pores with a pore diameter greater than 50 nm is higher than that in the micropores but lower than that in the mesopores. This may be related to the conversion of part of the liquid hydrocarbons into migrating solid bitumen. However, it is also related to the fact that some of the large and medium pores were not filled by liquid hydrocarbons but were filled by shale gas. From the correlation diagram of micropore volume, mesopore volume and chloroform pitch “A” content (Figure 12), it can be seen that the micropore volume has a weak correlation with the chloroform pitch “A” content, but it has a significant positive correlation with the mesopore volume.

Figure 12

Relationship between the content of chloroform pitch “A” and the volume of different types of pores. Notes: (a) micropore volume and (b) mesopore volume.