Lacustrine Shale Gas Reservoir in the Ordos Basin

CHAPTER 3

Lacustrine Shale Gas Reservoir in the Ordos Basin 93 Shale is one type of mudrock in the classification of sedimentary rocks. By definition, shale consists of clay- and silt-sized particles, has developed a laminated structure, and is composed of clay minerals, mixed with fine detrital clasts of minerals, such as quartz and feldspar, as well as chemical cements of calcium, iron, and so forth. Based on principles of petroleum geology, shale is the cap rock of conventional oil and gas reservoirs and the shale rich in organic matter is a hydrocarbon source rock. The practice and study of shale gas exploration in recent years have demonstrated that shale rich in organic matter can not only generate natural gas itself, but also can accumulate and reserve the natural gas to form a shale gas reservoir. Therefore, shale can be a hydrocarbon source rock and a reservoir, and shale gas can be hosted in the reservoir space of shale in many modes of occurrence.

SECTION 1  LACUSTRINE SHALE GAS RESERVOIR AND ITS CHARACTERISTICS Compared with the conventional oil and gas reservoir, the shale reservoir has greater particularity in terms of lithology, physical properties, and gas-bearing capacity. Shale gas has the geological characteristics of self-generating, self-reserving, accumulation using adsorption, and cryptic forms of accumulation that are totally different from conventional natural gas. Due to the unusual porosity structure of shale reservoirs and the unusual modes of occurrence of natural gas therein, the method of evaluating the conventional reservoir of oil and gas is difficult to apply to the unusual shale gas reservoir. The definition and evaluation of shale gas reservoirs are under study, and there are many factors that influence the geological characteristics of shale reservoirs. Therefore, shale reservoirs can be evaluated in detail only after the definition and particularities of shale gas reservoirs are thoroughly understood.

1  LACUSTRINE SHALE RESERVOIR Lacustrine shale reservoir refers to those formed in the lacustrine sedimentary environment. It mainly consists of clay minerals, and is developed with a laminated structure. It is a widely distributed sedimentary rock, and shale gas literally refers to the hosting of natural gas in shale. However, the use of the term Lacustrine Shale Gas. http://dx.doi.org/10.1016/B978-0-12-813300-2.00003-9 Copyright © 2017 Petroleum Industry Press. Published by Elsevier INC. All Rights Reserved.

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Lacustrine Shale Gas shale herein refers not only to the pure shale, but also to interbeds in the shale, such as siltstone, fine sandstone, silty or sandy mudstone, and carbonate. As an emerging nonconventional energy, no definitive standards are specified for shale gas in China as of yet. The Chang 7 and Chang 9 Shales in the southern region of the Ordos Basin feature “Three High” in well logs, due to the high content of radioactive minerals and organic matter (Fig. 3.1). The natural gamma ray (GR) reading of the Chang 7 Shale is usually between 90 and 250 API, with an average as high as 140 API. It is usually between 150 and 270 API for the Chang 9 Shale, with an average as high as 190 API. The reading of sonic transit time value is usually between 250 and 360 µs/m, with an average value in the gas-bearing shale section of around 300 µs/m. The deep induction resistivity value is usually higher than 35 Ωm, with an average of 70–80 Ωm. Based on the core lithology, natural GR signature, sonic transit time and resistivity curve, the shale and interbeds can be clearly distinguished. With reference to reservoir standards for shale gas recommended by the China National Energy Administration, these are based on the experiences of exploration and study of the Yanchang shale gas of the Ordos Basin, and the limitations of fracturing technology. A shale gas reservoir must possess the following: (1) the thickness of shale must be larger than those of other interbeds above and beneath; (2) the thickness of sandstone or other lithostrome must be less than 30% of the total reservoir thickness; and (3) the TOC of the shale should be higher than 0.5%. According to the ratio of interbed thickness as a proportion of the total reservoir thickness, the shale reservoir can be further divided into shale reservoir and interbed-containing shale reservoir. The thickness of interbeds accounts for less than 10% of the total reservoir thickness in shale reservoirs, and 10%–30% for interbed-containing shale reservoirs. Based on the results of the classification using the aforementioned criteria, fracturing tests were conducted in the shale reservoir and relatively good results were obtained. For example, Well LP177 gives an initial daily production of 2350 m3 after fracturing, TOCs are all higher than 4%, and the adsorption capacities are all higher than 1.1 m3/t. The natural GR signature is 117.4–208.1 API, the sonic transit time is 221.4–323.9 µs/m, and the resistivity is 46.9–105.2 Ωm. The adsorbed gas content interpreted from well logging is 0.87–1.46 m3/t.

2  PARTICULARITY OF LACUSTRINE SHALE GAS RESERVOIRS 2.1  Union of Source and Reservoir Different from the conventional oil and gas reservoir, the gas-bearing shale is not only the hydrocarbon source rock of natural gas, but is also the reservoir and cap rock that accumulates and preserves natural gas with a typical “self-generating and self-reserving” character (Fig. 3.2). The organic geochemical properties of shale not only limit its hydrocarbon-generating properties, but also influences the gas-bearing properties of the shale reservoir. As pointed out in Chapter 1, the

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.1 Lithological characteristics of the Yanchang shale.

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FIGURE 3.2 System of self-generating and self-reserving of shale gas (Jarvie et al., 2003).

indices to evaluate the organic geochemistry of shale mainly include the type of organic matter, abundance of organic matter, and its maturity. The type of organic matter is an important parameter to evaluate the hydrocarbon-generating potential of shale. It is assessed using the kerogen type, and the organic matter of lacustrine shale is mainly of the humic type. The maturity of organic matter reflects the temperature conditions experienced, which enables an assessment of whether shale can generate gas. It is mainly assessed by measuring the reflectivity of vitrinite. These indices change greatly depending on the different basins and different stratigraphic positions of the shale. Therefore, a comprehensive evaluation should be conducted, incorporating the specific characteristics of the regions studied.

2.2  Complexity of Lithology Shale gas literally refers to the natural gas borne in shale. However, the shale strata on the geological section does not consist of only a single mudstone or shale bed. In the lithological layer mainly consisting of shale, the shale formation often has some relation spatially with thin layers (interbeds) of fine sandstone, siltstone or carbonate, for example, overlapping and interbedding, or as irregular lens of fine sandstone, siltstone, or carbonate. The existence of interbeds in shale will play some active part in the accumulation and later exploitation of shale gas. Because the fine sandstone, siltstone, and carbonate possess relatively good porous properties, this provides relatively high quality void space for the accumulation of shale gas. Meanwhile, the fine sandstone, siltstone, and carbonate mainly consist of brittle minerals, which are favorable to hydraulic fracturing, and so will be advantageous to shale gas exploitation. The lacustrine shale interbeds mainly consist of sandy layers and silty layers and the shale, where the sandy layers and silty layers are interbedded frequently. Therefore, this lithologic assemblage is favorable for the accumulation, storage, and preservation of shale gas.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 Analysis of the mineral composition of the Yanchang Shale in the Ordos Basin indicates that the lacustrine shale has a complex composition that includes clay minerals, quartz, feldspar, carbonate, and so forth. The common clay minerals, include kaolinite, illite, chlorite, smectite, mixed layer illite-smectite, and so forth. The clastic minerals in shale are mainly terrigenous, including quartz, feldspar, mica, and rock particles. Shale also contains many authigenic minerals that are formed during diagenesis, such as iron oxides (limonite, magnetite), carbonates (calcite, dolomite, and phosphosiderite), sulfates (gypsum, anhydrite, barite, etc.), sulfides (pyrite, etc.), and there can also be glauconite and organic matter. The variation of the mineral compositions in shale influences the shale in terms of its mechanical properties, pore structure, and its adsorption capacity for natural gas. Generally, compared with the brittle minerals, such as quartz and calcite, the clay minerals have more micropores and higher surface area. Thus, clay minerals have stronger adsorption capacity for natural gas. However, where saturated with water, clay minerals show a greatly decreased adsorption capacity for natural gas. On the other hand, an increase in the contents of quartz and carbonate minerals can enhance the brittleness of the rock, which is favorable to form natural fractures, and will provide accumulation space for free gas and improve the accumulation and seepage performance of the shale. Meanwhile, the phenomenon of quartz secondary overgrowths, and the effect of calcite cementation occurring during the process of burial diagenesis can possibly reduce the porosity of shale. Thus, upon evaluating a shale reservoir, a balance among clay minerals, water saturation, quartz, and carbonate contents must be sought. Because the relative porosity and permeability of shale is low, the selection of a preferred target must consider the opposing relationships between the gas content in the reservoir (free gas volume and adsorbed gas volume) and the degree of ease of fracture. For the lacustrine shale, if the content of clay mineral components is relatively high, and the content of brittle mineral components is relatively low, its degree of ease of fracture will be low.

2.3  Physical Compactness A large amount of analysis and tests demonstrate that the mineral grain of shale has a size generally smaller than 63 µm, a size of micropore and microfractures usually smaller than 50 µm, a very low porosity, an effective porosity usually less than 10%, a permeability usually in the range of 1 × 10−6–1 × 10−4 mD, and both poor accumulation capacity and seepage capacity. Because the methane molecule, as the main component in natural gas, has a diameter 0.38 nm, it can exist on the surfaces of organic matter and clay minerals in the adsorbed form or occur in the micropores and microfractures in free form. Therefore, by comparing the absolute sizes of methane as well as the micropores and microfractures in a shale reservoir, it can be determined whether the micropores and microfractures in shale can effectively accumulate methane gas, and thus form an effective reservoir. Compared to marine shale, there are sandy or silty interbeds generally developed, and various types of pores in lacustrine shale. Besides the micropores

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Lacustrine Shale Gas and microfractures in shale, there are also various pores in the sandy or silty interbeds. Based on the relationship between porosity and permeability, a lack of deformation of the original shale reservoir can have a disproportionate effect on the porosity and permeability as a whole. This is also the main characteristic of reservoirs with ultralow permeability. The development of fracture has a large influence on the permeability of shale, such that if a fracture develops, a small porosity can translate into relatively high permeability. In contrast, if no fracture is developed, the permeability of a shale reservoir can be very low, even though the porosity is high.

SECTION 2  TEST OF LACUSTRINE SHALE GAS RESERVOIRS The analysis and tests on shale gas reservoirs is an issue that has been focused upon in the recent years. Usually, various analytical and test methods are used in terms of the pore type, the pore structure and the pore permeability of shale. As a whole, these methods fall into two categories. The first is to use direct observation methods using an electronic microscope, SEM, and so forth. to qualitatively observe the pore type, size, and pore structural characteristics of shale. The other is to use test methods, such as the mercury-intrusion method, gas-adsorption method, or pulse-decay method to quantitatively measure the parameters of shale physical properties, such as pore-size distribution, specific surface area, porosity, and permeability. This section will concisely introduce the observation and test methods commonly used in the study of shale reservoirs.

1  SEM OBSERVATION METHOD Because shale is relatively compact, shale gas is mainly accumulated in the nanoscale pores and partial micropores and microfractures. As such, the ordinary optical microscope cannot provide the observational resolution to meet the requirements of shale gas research. Therefore, analysis using an SEM supported with an energy dispersion system (EDS) spectrum are mainly employed to observe and analyze the pore characteristics of shale. The SEM analysis on shale samples used in this work were mainly carried out in the Beijing Center for Physical and Chemical Analysis. The instrument model used is S4800 Cold Field Emission SEM with a theoretical resolution at 15 kV of 1.0 nm, and a maximum magnification of X800,000. Because the rock sample is nonconductive and contains organic matter, the actual resolution can only be around 10 nm, even after gold plating. Therefore, this study also employs EDS supported SEM to probe the elements in the range of B to U, in order to identify the chemical constituents in the various minerals and the materials occurring in the pores. In order to fully examine the development characteristics of pores in shale, two sets of samples can be prepared for SEM observation. One set uses a shale sample with fresh fracture, and the sample constitutes a shale fragment with the edge lengths of 0.5 cm × 0.5 cm × 0.5 cm. The shale

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.3 Characteristics of SEM images of samples of the Yanchang Shale in well cYY16, 1400.63m. (A) SEM image of fresh fracture. (B) SEM image of Ar-ion-polished sample.

sample is sprayed with gold before observation. Because such samples retain the relationship between mineral form and hydrocarbon occurrence, it can be used to observe the form of the minerals in the shale, the contact relationships between each of these, and the 3D spatial characteristics of the pores. The second set uses an Ar ion polished piece of shale sample, which is prepared as follows. First, cut off a shale sample with a size of 0.5 cm × 1 cm along the direction perpendicular to the bedding direction. Then, grind the shale with 2000 mesh abrasive paper. When the sample is ground to a thin wafer that is about 0.1 mm in thickness, place it into an Ar ion polisher to carry out ion thinning. The Ar ion polisher runs on the principle of ion sputtering to implement ion thinning based on ordinary polishing. It has a sputtering rate of 28 µm/h especially suitable for fragile plastic shale, and can effectively carry out gentle polishing and cleaning. The polished sample is sprayed with gold before observation. Because the original crystal and particle morphology of the sample is altered during polishing, it is difficult to identify the relationship between the mineral grain morphology and particles, but it is beneficial for the observation of the developmental characteristics of the pores, and for confirming the parameters of pore size, porosity, and so forth (Fig. 3.3).

2  MERCURY INTRUSION METHOD The mercury intrusion method is a quantitative method for analyzing physical properties by intruding mercury into the rock sample to test the pore structure of the sample. It determines the rock pore structure by the function relation between the mercury intrusion pressure and the amount of intruded mercury. Generally, the mercury intrusion method is suitable to test samples developed with mesopores-macropores to ultramacropores, and returns a good correspondence to such pores. Based on the range of minimum test apertures, this method can be divided into the high-pressure mercury-intrusion method

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Lacustrine Shale Gas and conventional mercury-intrusion method. The high-pressure mercury-intrusion method uses a regular core with a diameter of 2.5 cm and a length of no more than 5 cm, and can measure a minimum aperture of 3 nm. Although the conventional mercury intrusion method can also intrude the mercury into a 3.6 nm pore under the maximum design mercury intrusion pressure, because the test samples consist of irregular debris fragments of about 1 cm3, and tend to fracture under excessive mercury intrusion pressure, the effective measurable aperture is 7 nm. Because lacustrine shale often contains sandy or silty interbeds or laminae, so the conventional mercury intrusion method can be used to carry out the test based on the China National Standard GB/T 21650.1-2008. The instrument used in this work is an Automatic Mercury Porosimeter (PoreMasterGT 60) by US Quantachrome Corp. The test unit is in the Beijing Center for Physical and Chemical Analysis. A total of 12 samples from the Yanchang Chang 7 and Chang 9 Shales from the south of the Ordos Basin were tested with the mercuryintrusion method. Because the Yanchang Shale from the south of the Ordos Basin is widely developed with silty laminae, in order to compare the differences in physical properties between the silty laminae and the pure shale, silty laminae were separated from three shale samples in order to run the mercury intrusion test separately on the silty laminae and the nominally pure shale. The samples were not treated by washing oil in advance, and were vacuumized before the mercury intrusion test. To ensure the reliability of the test results, only one sample is placed in the sample chamber during the primary mercury-intrusion test to ensure that the pore space of the rock sample will not be calculated in the final test results. To quantitatively study the characteristics of pore-size distribution and test the porosity (corresponding to the range of pore size from 7 nm to 200 µm), a He densimeter was used in the test, and the skeletal density of the rock was also tested as a reference.

3  GAS-ADSORPTION METHOD The gas-adsorption pore-size (pore volume) distribution test mainly utilizes the phenomenon of capillary condensation and the principle of volume equivalent substitution to establish a capillary condensation model. Further, it estimates the characteristics of pore-size distribution and pore volume with the premise that the assumed shape of pores is a cylindrical pipe. By measuring the volume of condensed gas under different pressures [pressure (p)/saturation pressure (po)], the isothermal adsorption/desorption curve can be plotted to acquire the pore volume and pore size distribution curve for the sample using various theoretical models. Based on various pore-size ranges measured, the gas-adsorption method can also be divided into two methods—namely, nitrogen adsorption and CO2 adsorption. The former method is mainly to measure the mesopores of 2–50 nm and the macropores below 100 nm. The latter method is mainly to measure the pore structure of micropores smaller than 2 nm, because CO2 gas has a higher diffusion rate than N2 under the experimental conditions, and it is easier to achieve saturation adsorption.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 Based on the different purposes of the study, two groups of tests for shale pore structure were designed. One group employed the N2 adsorption method to test the pore structure of a total 14 whole rock samples of the Yanchang Chang 7 and Chang 9 to complement the tests of rock mineral compositions, pyrolysis, and adsorption capacity of shale. The tests with this method were conducted at the Guangzhou Institute of Geochemistry, Chinese Academy of Sciences, where the main purpose was to measure the specific surface of micropores and the structural parameters of mesopores to ultramacropores (1.74–300 nm). To complement the mercury intrusion test, another group of samples were also tested by separating the silty laminae from the shale (the three samples are deep core samples from Zhangjiatan Shale section in Well YY7). The silty laminae and the shale were ground to rock powder with a size lower than 250 µm, and then dried and degassed at a temperature of 80°C. Then, the N2 adsorption method and the CO2 adsorption method were employed to test the pore structure of the silty laminae and the shale, respectively. The N2 adsorption method is mainly to measure the specific area and the characteristics of pore size of mesopores and macropores (3–109.8 nm). The CO2 adsorption method is mainly to measure the specific area and the pore volume of the micropores (0.3–1.5 nm). This test was carried out in the Beijing Center for Physical and Chemical Analysis. The instrument used was a Surface Area and Porosity Analyzer (Surface Area and Porosity Analyzer) by US Quantachrome Corp. The isothermal adsorption/ desorption curves were tested and analyzed according to the China National Standard GB/T 21650.1-2008. In order to quantitatively study the characteristics of pore-size distribution and test the porosity, a He densimeter was also used in the test, and the skeletal density of rock was tested as the reference. When analyzing original adsorption and desorption data of shale, it is necessary to select an appropriate theoretical model to interpret the specific area and pore-size distribution. So far, the relatively advanced mesopore specific area analytical model is the multi-point Brunauer-Emmett-Teller (BET) model, which analyzes the specific area when p/po is in the range of 0.05–0.35, by establishing the relationship between the actual adsorption volume V and the monolayer adsorption volume Vm. Because the monolayer adsorption tends to occur in the micropores, it is more appropriate to use the Langmuir specific area value proposed for the monolayer adsorption theory. Therefore, the BET specific area interpretative model is used for the mesopore specific area, and the Langmuir specific area interpretative model is used for the micropore specific area. For the results of pore-size distribution measured by the N2 adsorption method, the Barrett-Joyner-Halenda (BJH) theoretical model is the most commonly used, and is employed for the interpretation, that is, the Kelvin equation is used to establish the relationship between relative pressure and pore size. In addition, the gas-adsorption tests all employ the adsorption curves to interpret the pore-size distribution. Practice and theory have demonstrated that if the desorption curve is used to analyze the pore-size distribution of mesopores, and the interpretative results of all the samples will produce one abnormally

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FIGURE 3.4 Pore-size-distribution characteristics of the Yanchang Shale measured by the adsorption curve method (upper) and the desorption curve method (lower).

high peak at 4 nm (Fig. 3.4). However, this peak value is not a reflection of the real internal structure, but the influence of the combined pore-network system of coexisting of macropores, mesopores, and micropores to the desorption process. As shown in Fig. 3.5, the pore-size distribution model established with the adsorption curve can exclude this false impression and improve the precision of the interpretation. The Kelvin equation is not suitable for measuring the pore size distribution by the CO2 adsorption method. Because the adsorbates filling in the micropores are not in the form of liquid, if the pore size is <2 nm, the macroscopic thermodynamic methods, such as BJH model, are no longer applicable to the interpretation of micropore size distribution. Nevertheless, the nonlocal density functional theory (NLDFT) model can be used to carry out pore size analysis on the CO2 isothermal adsorption curve. Compared with the conventional t-graph method (MP method) and the empirical methods, such as HK and SF,

FIGURE 3.5 Combined pore-network system in shale (Groen et al., 2003).

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 this model can produce a micropore volume that has not merely relative meaning, but is a real quantitative analysis of micropores. Therefore, the results can be compared to the pore volume obtained by the N2 adsorption method.

4  PULSE DECAY METHOD As shale has very poor porosity and permeability, and shale is easy to expand when wet, so the conventional porosity test methods (such as the mercury intrusion method) and the liquid permeability test methods (such as the steady-state method) are not suitable to test the physical properties of shale. So far, China often uses the nonsteady-state pulse-decay method to measure shale permeability, where He gas is used as the test gas to possibly measure the two physical properties of shale, porosity, and permeability. The working principle of the pulse-decay method to measure permeability is to first apply a pore pressure on the core, then, transmit a differential pressure pulse through the core. As the pressure is transmitted through the core in a moment, the computer data-collection system records the pressure difference between two ends of the core, the downstream pressure and the time. Meanwhile, the software plots the logarithmic curve between the pressure difference and average pressure and time, and the software calculates the permeability by a linear regression of the pressure and time data. The system uses very small amounts of pressure difference to reduce the effect of non-Darcy flow, and tests many points by changing the pore pressure, that is, the conventional method can be employed to calculate the klinkenberg permeability. The range of tested permeability is 0.00001–10 mD. The working principle of gas-logging porosity is similar to the true densimeter, where the principle of He gas expansion is used to measure the rock skeleton volume and the gas charge pore volume, and then calculate the porosity of the rock sample. Because the He molecule has a tiny diameter (0.25 nm) and has no adsorption ability, it can freely penetrate into various levels of pore sizes. Thus, the measured porosity will also include the micropores and is the maximum pore volume that the methane molecule can enter. The possible range in porosity amenable to the test is 0.01%–40%. A sample collector was used to drill a cylinder with a diameter of 2.5 cm and a length of 3–5 cm from the shale core, then the two ends were cut flat. Then the sample was placed in a vacuum to dry before being tested in the instrument. The data from the pulse decay test listed in this book were obtained by the Institute of Porous Flow and Fluid Mechanics, Chinese Academy of Sciences. The instrument used was the PoroPDP-200 by US Core Lab. The test was carried out at room temperature and the confining pressure of the test was fixed at 6.89 MPa, to reduce the gas slippage effect as much as possible. The test standard was based on the American Petroleum Institute (API) RP-40. Because the shale samples were fragile, only a few groups of samples were prepared, which included the shale containing sandy laminae, the sandy interbeds from the shale, and the nominally pure shale. The pulse decay method was employed to test their porosity and permeability.

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Lacustrine Shale Gas SECTION 3  DISTRIBUTION OF LACUSTRINE SHALE GAS RESERVOIR The Ordos Basin mainly developed deposition of deep-lake facies, coastal shallow-lake facies, and delta facies during the period of the Yanchang Chang 7 to Chang 9 deposition. The “Lijiapan Shale” and “Zhangjiatan Shale,” which have distinctive characteristics in terms of lithological and electrical properties, were developed at the top of the Chang 9 and at the bottom of the Chang 7, respectively. The distribution characteristics of Lijiapan Shale and Zhangjiatan Shale are identified in the key well profiles using well logging information. On this basis, the distribution characteristics of Zhangjiatan Shale and Lijiapan Shale reservoirs are surveyed vertically and horizontally.

1  GEOLOGICAL BACKGROUND OF LACUSTRINE SHALE DEVELOPMENT The Ordos Basin began to enter a period of development of an inland depression and lake basin during the Late Triassic. The lake basin developed a complete cycle of sedimentary basin evolution, from the lake-delta facies to deep water lake facies, during an evolution involving generation-development-subsidence. In the early stage of deposition of the Triassic Yanchang Formation, the basin subsidence rate clearly increased, the southern basin was almost completely inundated by lake water, and the lake shoreline migrated outward substantially to cover the area of the lake basin on a large scale. The period of deposition of the Yanchang Chang 9 Shale was the stage in which the lake transgression mainly developed, and the deposition was basically argillaceous. There was a near-source delta sand body developed only in the northeastern and eastern margins of the basin (Fig. 3.6). The deep lake facies in the period of the Chang 9 deposition was mainly developed in an area circumscribed by the line of Dingbian-Wuqi-Zhidan-Zhiluo-Malan-Changwu-Ningxian-Taibai- Huachi. However, the shallow-lake facies varied rather greatly in different areas, occurring as wide in the northeast and southwest and narrow in the southeast and northwest. The thickness of the shale is 10–50 m. Drilling and core data reveal that the lithology of the Chang 9 Shale is black silty mudstone and mudstone (shale), most of which are fine sedimentary rocks, and relatively few purely dark mudstone. After the Yanchang Formation entered the period of the Chang 7 deposition, the whole basement of the basin underwent intensive tensional thinning and began to subside, causing the water to deepen. The development of the lake basin then reached its zenith. During this period, the semideep to deep-lake center was located within the wider region of Qingyang, Zhengning, Zhiluo, Wuqi, Yanchi, Huanxian and Yan’an-Fuxian, as well as the east, and distributed asymmetrically along a northwest-southeast orientation. Meanwhile, there were also dark gray and gray-black mudstone and oil shale developed here with abundant organic matter. Therefore, this is the main region of development of oil-generating rocks. The shallow lake facies was still distributed in a zonal pattern around the semideep lake area. It was wide in the east, and the lake-basin

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.6 Map of sandstone-stratum ratio of the Yanchang Chang 7-Chang 10 period in the Ordos Basin.

margin was around Ansai-Zizhou. The overall superimposed thickness of the Chang 7 dark mudstone (shale) is around 45–100 m, where the thickness of a single layer can reach 40 m. Northeast of the center of subsidence, the thickness of shale has a tendency to decrease gradually. Within the area of the subsidence center, the region of Zhidan-Ganquan-Fuxian is the main sedimentary center (i.e., depocenter), with the shale thickness being generally higher than 50 m, and the maximum thickness being over 100 m. The region of Dingbian-Wuqi is a secondary sedimentary center with the thickness of shale being around 50 m.

2  IDENTIFICATION OF LACUSTRINE SHALE GAS RESERVOIR 2.1  Characteristics of Shale Well-Logging Response The biggest characteristic of gas-bearing shale is its high content of organic matter. Thus, some routine well-logging data series, such as the logging profile of natural gamma ray (GR), sonic wave, and resistivity, should prove to be

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Lacustrine Shale Gas beneficial when used as an indicator. The organic matter in gas-bearing shale often contains adsorbed uranium isotopes. In addition, the adsorption effect of clay particles will lead to an increase of the GR signature. The organic matter and the rock matrix have a very different effect on the density of shale. The higher the content of organic matter, the lower the density and, hence, the larger the sonic transit time. Therefore, the density of gas-bearing shale formations is usually lower than that of a shale lean in organic matter, with otherwise similar lithology, and this increase in the sonic transit time is also obvious. Meanwhile, due to high resistivity of organic matter, the gas-bearing shale layer often has high resistivity. Thus, the comparison between shale cores and well-logging profiles usually shows that the well-logging profile of a gas-bearing shale layer has the electric characteristics of “Three High, One Low,” that being high GR signature, high sonic transit time, high resistivity, and low density (Table 3.1 and Fig. 3.7). The strong-reducing sedimentary environment of the Yanchang Chang 7 semideep- to deep-lake facies in the Late Triassic in the Ordos Basin provided a good sedimentary environment for the development of oil shale. Observations on drill cores indicate that the appearance of the Chang 7 oil shale is black and monotonous, in which the lamination is rather well developed with ostracods and scale fossils contained occasionally, and deep water sedimentary structures, such as sand-filled mud, can also be found, and where the characteristics of deep-lake facies are obvious. The Chang 7 oil shale shows the remarkable characteristics of low potential, high GR signature, high resistivity, and low density on the complex well-logging chart, which are obviously different from those of the silty mudstone and mudstone of the lake facies. Therefore, the complex well-logging chart can be used to effectively identify and further understand the characteristics of the spatial distribution and development scale of the shale. The Zhangjiatan Shale was developed at the bottom of the Yanchang Chang 7 oil-bearing strata, and the Lijiapan Shale was developed at the top of the Yanchang Chang 9 oil-bearing strata. They are the traditional marker beds for comparison of the Triassic Strata in the Ordos Basin with the characteristics of high gamma, enlarged well diameter, high resistivity and high sonic transit time, where the profile of the sonic transit time features high in the lower (Lijiapan), and low in the upper (Zhangjiatan) (Fig. 3.7).

2.2  Concept of Well-Logging Interpretative Model Previous studies have indicated that the gas-bearing properties of shale reservoirs are related to factors, such as formation temperature, pressure, mineral components, porosity, saturation, and gas properties. The methods to acquire these key factors include core measurement, geophysical well-logging, as well as well drilling, and logging. Of these methods, the core analysis allows samples to be taken continuously from the formation in a given section and is the most reliable method. It is also the method generally used to take samples directly for testing of the physical properties of the rocks. However, because the cost of core analysis is high and the duration of measurement is long, the test is usually carried out in only a few cored wells, whereas most other wells are seldom cored.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 Table 3.1   Well-Logging Response Characteristics of Shale-Gas Reservoirs (Pan et al., 2009)

Well-Logging Series

Output Parameters

Characteristics of Profile Influencing Factors

Natural gamma and energy spectrum

U, Th, K, GR

High value The higher the content (>100 API) and of mud, the higher the locally low value natural gamma (GR) value. The organic matter contains highly radioactive elements

Well diameter

CAL

Hole enlargement

Enlargement of argillic formation, the presence of organic matter increases the enlargement more seriously

Sonic transit time AC

Relatively high with cycle skip

The higher the organic matter abundance, the bigger the AC. The sonic wave value increases as the gas content increases. Cycle skip occurs at fracture to cause enlargement of well diameter

Neutron porosity

CNL

Medium value

Bound water leads to higher measured value and the increase of gas content leads to lower measured value. The neutron porosity in the fractured region is high

Litho-density

DEN

Mid-low value

The litho-density decreases as the gas content increases. The organic matter leads to lower measured value and the fractured formation has lower density value and enlarged well diameter

PE

Low value

The measured value of hydrocarbons is low and the increase of gas content leads to lower measured value. The neutron porosity in the fractured region is high (Continued)

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Lacustrine Shale Gas Table 3.1   Well-Logging Response Characteristics of Shale-Gas Reservoirs (Pan et al., 2009) (cont.)

Well-Logging Series

Output Parameters

Characteristics of Profile Influencing Factors

Dual lateral Microsphere

RD, RS and PFOC

Low value as a whole and locally high value; shallow and deep lateral curves nearly overlap

Continuous inclination

HAZ and DEVI

Mud and bound water both lead to low resistivity and organic matter leads to high resistivity

Used to comprehensively evaluate engineering and gas reservoir

FIGURE 3.7 Characteristics of the well-logging profiles of the Yanchang Zhangjiatan Shale and Yanchang Lijiapan Shale in the Ordos Basin.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 Geophysical well-logging can acquire the logging responses of the physical properties of reservoir rocks in a continuous depth range, Thus, the physical properties of the rocks, such as resistivity, sonic transit time, bulk density and hydrogen index, and so on, can be acquired indirectly. Moreover, these data are collected at the conditions of underground temperature and pressure, so it is closer to the actual in situ conditions of the rocks. The low cost and high efficiency of well logging renders it the method that must be applied in nearly all drilled wells. Thus, calculation of the parameters of a shale reservoir using the welllogging data is more widely used than core analysis and direct measurement. It has been the most important means of evaluating shale reservoirs. Because well logging is a method to indirectly measure the parameters of shale reservoirs, it needs to establish models for the shale formations, and equations for the well-logging parameter responses (i.e., the well-logging interpretative models), in order to evaluate and analyze the well logging of shale reservoirs. Then, these well-logging interpretative models form the basis to calculate the parameters of the reservoir properties.

2.3  Establishment of Well-Logging Interpretative Model of the Yanchang Shale There are huge differences in many factors between shale and conventional hydrocarbon reservoirs. Therefore, the methods of evaluating well logging for them are also different. First, the accumulation state is different, as the shale features low porosity, very low permeability, self-generation, and selfreserving. Second, the modes of occurrence of fluids in shale reservoirs are different and, more importantly, the lithology of shale reservoirs is more complex than the conventional hydrocarbon reservoir. The shale gas reservoirs known thus far to have commercial value to exploit are mostly shale formations, where the content of silica minerals is higher than 28%, and where microfractures are developed. Thus, the interpretative models for shale gas well logging are completely different from those for conventional hydrocarbon reservoir. The purpose of studying the mineral components of shale is to clarify the mineral composition of the shale reservoir, and confirm the rock matrix of the reservoir, to provide the basis for the calculation of the parameters, such as porosity. The reservoir of a shale gas is a compact reservoir with low porosity and very special permeability. The effective exploitation of shale gas always needs reservoir reconstruction, and the content of brittle mineral components in the shale will influence the effect of reservoir reconstruction. Therefore, the analysis of the mineral components of shale has important implications for the exploitation of shale gas. In addition, to evaluate the gas-bearing properties of shale, the content of organic matter, the porosity, and the saturation of the shale need to be determined. Therefore, it is an important foundation to confirm the mineral components of the shale in order to establish a well logging interpretative model for the southern region of the Ordos Basin.

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Lacustrine Shale Gas Based on the corresponding relationships between lithological and electrical properties, a lithological identification graph of well-logging data is generated to identify the lithology of the non-cored section (or well). This method of lithological well-logging identification is commonly used, and by virtue of the universality of well-logging data, it is applied widely and serves to great advantage. In order to implement well-logging lithological identification, first, the type of lithology must be discriminated; second, the lithology identification graph must be established; and finally, the well-logging lithologies must be identified and verified.

2.3.1  DIVISION OF LITHOLOGY TYPE In order to ensure the effective application of the well-logging lithological identification graph, it needs to discriminate the lithologies in the southern region of the Ordos Basin, albeit there should not be too many types. In light of the characteristics of the lithologies, well logging can be used in combination with the corresponding relationship between lithology and physical properties. The lithologies in the region are divided into five types, namely, fine sandstone, pelitic siltstone, silty mudstone, black mudstone (shale), and black oil shale. This is done based on observing and describing the cores at the cored intervals of the Yanchang Chang 7 and Chang 9 Shales. 2.3.2  ESTABLISHMENT OF THE LITHOLOGICAL IDENTIFICATION GRAPH According to the lithologic characteristics of the Yanchang Formation in the southern region of the Ordos Basin, and the characteristics of well-logging profile of lithological response, six well-logging profiles, including natural gamma ray (GR), density (DEN), resistivity (RT), neutron porosity (CNL), sonic AC and apparent neutron porosity (∆PHI) are selected to establish the lithological identification graph in order to conduct shale lithology identification. Because there is inadequate well-logging data for this region, and only six wells have density logging, two different compound modes of well-logging (i.e., with and without DEN) are used to establish the lithological identification graph.

2.3.2.1  Lithological Identification Graph With Density Profile Black oil shale contains high abundances of organic matter, as well as having high oil-bearing properties. Its density logging and resistivity logging responses are also obvious (i.e., low density (DEN) and high resistivity (RT)), which can thus be used to identify black oil shale. Compared with arenaceous rock (fine sandstone and pelitic siltstone), pelite (mudstone and silty mudstone) has the characteristics of high CNL and high GR. Therefore, these two profiles can be used to discriminate pelite from arenaceous rocks. The DEN and ∆PHI parameters exhibit large differences between fine sandstone and pelitic siltstone, while the sonic AC and the CNL parameters exhibit large differences between mudstone and silty mudstone. Therefore, these can be used to discriminate mudstone and silty mudstone, as well as fine sandstone and pelitic siltstone.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.8 Shale lithological identification with DEN profile of well.

The data of six wells containing density logging profile data in the southern region of the Ordos Basin are used to establish the well-logging lithological identification graph of shale gas as shown in Fig. 3.8. The procedure to identify the lithology with this graph is first to use the RT and DEN logging profiles to identify the oil shale (Fig. 3.8A). Then, the natural GR and CNL logging profiles are used to discriminate the arenaceous rocks (referring to fine sandstone and pelitic siltstone) and the pelitic rocks (referring to the mudstone and silty mudstone) (Fig. 3.8B). On the basis of this, the DEN and the ∆PHI profiles are used to discriminate the fine sandstone and pelitic siltstone in the arenaceous rocks (Fig. 3.8C). Meanwhile, the sonic AC and CNL logging profiles are combined to discriminate the mudstone and silty mudstone (Fig. 3.8D). According to the established shale well-logging lithological identification graph, and the process of lithological identification, the lithologies in the Wells LP1771, LP177-2, LP177-3, YY12, and YY13 in the southern region of the Ordos Basin are identified. The results reveal that the oil shale at the bottom of the Yanchang Chang 7, at an intermediate position in the Chang 8, and at the top of the Chang 9, are mostly gray mudstones interbedded with thin sandstones (Fig. 3.9), and sandstone thinly interbedded at the mid-lower part of the Chang 9.

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FIGURE 3.9 Lithological identification using DEN profile of wells [(A) well YY12 and (B) well LP177-1] in the Ordos Basin.

2.3.2.2  Lithological Identification Graph Without Density Profile Although the characteristics of the DEN logging response of oil shale and mudstone are obvious, some wells have no DEN logging. Thus, without density curves, the aforementioned lithological identification graph cannot be used to identify the lithologies in the well. In order to mitigate this obstacle, the three profiles of GR, AC, and RT are used to confirm another well-logging lithological identification graph (Fig. 3.10). Generally, the three well-logging profiles used in this graph are included as standard in well logging, such that this graph is applied rather widely. The procedure of lithological identification with this graph is slightly different from that with the lithological identification graph with DEN profile, as earlier. Thus, its identification sequence is as follows: 1. The combined sonic AC and GR logging are used to discriminate the mudstone, black oil shale and fine sandstone, pelitic siltstone, and silty mudstone (Fig. 3.10A). 2. Because mudstone and black oil shale have large differences in mineral content and in hydrocarbon-bearing properties, they also exhibit rather different characteristics in terms of sonic AC and RT logging responses (Fig. 3.10B). Thus, these parameters can be used to discriminate mudstone and black oil shale.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.10 Shale lithology identification without DEN profile from well.

3. Based on the differences in the GR and RT logging responses, fine mudstone, pelitic siltstone, and silty mudstone can be discriminated using the characteristics of these profiles (Fig. 3.10C). The shale lithological identification graph of wells without the DEN profile was used to identify the lithologies in Well YY1, Well YY6, and Well YY12. It was found that the lithology at the top and bottom of the Chang 7, at an intermediate position in the Chang 8, and at the top of the Chang 9 is mainly gray mudstone or thin siltstone (Fig. 3.11).

2.3.3  COMPARISON AND TEST OF IDENTIFIED LITHOLOGY Compared with the shale well-logging lithological identification graph with DEN, the shale well-logging lithological identification graph without DEN obviously used many fewer logging profiles, hence the degree of accuracy of the lithological identification may be slightly reduced. By comparing the identification results of both identification graphs, it was found that the identification results of both graphs were on the whole comparable (Fig. 3.12), although the effectiveness of graph identification with DEN profiles is slightly better (Fig. 3.13). There are relatively large differences between the two lithological identifications for the 1640–1670 m section of Well YY12 (within the red circle of Fig. 3.13).

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FIGURE 3.11 Lithological identification without DEN profile of wells [(A) well YY1 and (B) well YY6] in the Ordos Basin.

From the DEN curve, it can be seen that the rock density of the depth interval is clearly higher than the density of the upper black oil shale. The rock should have been identified as mudstone, as indicated by the gas logging, which also shows it is as normal. The mineral content in shale formations and their distribution have important influences on their gas-bearing properties, and also are key parameters to evaluate the potential economic exploitation of shale gas. For example, in order to drill and fracture a shale formation, it is preferable to select strata with low contents of clay minerals and high contents of brittle minerals (quartz and calcite, etc.). It can be determined from calculations that the Yanchang Chang 7 and Chang 9 Shales consist mainly of clay minerals and quartz, and that the content of organic matter is low in part because of the Chang 7 Shale, and that the content of organic matter decreases as that of quartz increases in the strata. The range in volume of kerogen is about 0%–13% and, in general, the volume ratio of kerogen also increases as the burial depth increases.

FIGURE 3.12 Comparison of results of shale lithological identification with and without DEN welllogging profiles of the well. (A) Well LP177-1 and (B) well YY13.

FIGURE 3.13 Comparison of identification effects of two lithological identification graphs. (A) Well YY12 and (B) well YY12.

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FIGURE 3.14 Calculation results of kerogen contents in the Yanchang Chang 7 Shale.

The shale-formation volume model was used as the basis to calculate the parameters, including the porosity of the Yanchang Shale, the content of kerogen, the content of clay, and the content of nonclay mineral particles, which are shown in Fig. 3.14. The depth interval shown in the diagram mainly corresponds to the Chang 7 Shale. The content of kerogen is the important factor in determining the gas content in shale, and is also a key parameter in determining other parameters, such as effective porosity and gas saturation. It can be determined from the calculations that the content of kerogen in the Chang 7 Shale is relatively low with a range around 0%–10%, which is positively correlated with the TOC and content of clay minerals, and is poorly correlated with the total porosity of the strata.

3  CHARACTERISTICS OF LACUSTRINE SHALE DISTRIBUTION A very important condition to form shale gas is that the shale is distributed widely. Adequate burial depth and thickness of the shale are requirements to ensure shale gas accumulation. In order to form a shale gas reservoir with commercial exploitation, the shale must have a certain minimum thickness and have an extensive area of continuous distribution. It can only form an effective hydrocarbon-source rock and reservoir in this way. The Yanchang Chang 7 and Chang 9 oil shales in the southern region of the Ordos Basin feature ”Three High” in well-logging profiles, due to the high content of radioactive minerals and high content of organic matter, that is, high natural GR, high sonic AC and high RT. The natural GR signature of the Chang 7 Shale is usually between 90 and 250 API, with an average high of 140 API. The GR signature of the Chang 9 Shale is usually between 150 and 270 API, with an average high of 190 API. The sonic AC value is usually between 250 and 360  µs/m, with an average value in the gas-bearing shale section of around

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 300 µs/m. The deep induction resistivity value is usually higher than 35 Ωm, with an average of 70–80 Ωm. Because of differences in core lithology, the natural GR, sonic AC and RT profiles can be used to effectively discriminate shale and interbeds. Arenaceous interbeds thicker than 3 m are excluded. Based on the results of the lithological discrimination, a fracturing gas test was conducted in the shale, and a relatively good result was obtained. For example, well LP177 gives an initial daily production of 2350 m3 after fracturing, and its shale TOC values were all higher than 4%, with adsorption capacities all higher than 1.1 m3/t. The natural GR was 117.4–208.1 API, the sonic AC was 221.4–323.9 µs/m and the resistivity was 46.9–105.2 Ωm. The adsorbed gas-bearing content from interpretation of well-logging was 0.87–1.46 m3/t. Based on the results of the lithological identification for the shale gas wells in the south of the Ordos Basin, and some oil exploitation wells, the burial depth of the top of the Chang 7 Shale is in the range of 600–1800 m within the research area located to the southeast of the lake basin center, and shallows-up gradually from the northwest to the southeast. The shale is deepest in the northwest, where the normal burial depth is greater than 1400 m, with the maximum depth of 1900 m. The burial depth in the southeast is relatively shallow, and is usually less than 1000 m. The shale has a range in thickness of 20–71 m, although mostly concentrated in the 30–60 m range. The shale is distributed with good longitudinal (i.e., vertical or downhole) continuity, and is thick in the west and thin in the east (Figs. 3.15 and 3.16).

FIGURE 3.15 Isopach map with contoured thicknesses of the Yanchang Chang 7 Shale in the south of the Ordos Basin.

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FIGURE 3.16 Connected-well profiles in pseudo-cross-section of the Yanchang Chang 7 Zhangjiatan Shale in the south of the Ordos Basin.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.17 Isopach map with contoured thicknesses of the Yanchang Chang 9 Shale in the south of the Ordos Basin.

The thickest section of the Yanchang Chang 9 Shale is located in the southeast of the Xiasiwan region. The burial depth of the top of the shale is 800–1900 m, with a maximum burial depth of 2100 m, and an average thickness of 15 m, although the thickness in the region varies greatly. The trend in the variation of the burial depth is basically consistent with the Zhangjiatan Shale. The burial depth in the northwest is greater than 1600 m, and is usually less than 1000 m in the southwest, where the shallowest location is less than 850 m deep. The thickness of the Chang 9 Lijiapan Shale is relatively thin at 6–31 m (Figs. 3.17 and 3.18). The two sets of shale contain abundant organic matter, which provides favorable sedimentary conditions for the development of gas-bearing shale. Meanwhile, as a lacustrine shale, the hydrodynamic environment of frequent transgressive and regressive lake movements results in the development of sand interbedded in the lacustrine shale. Thus, the thick layer of shale is divided vertically to allow the single shale layers with a planar scale of distribution that are finer than those of marine facies.

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FIGURE 3.18 Connected-well profiles in pseudo-cross-section of the Yanchang Chang 9 Lijiapan Shale in the south of the Ordos Basin.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 SECTION 4  PETROLOGY AND PORE PERMEABILITY CHARACTERISTICS OF LACUSTRINE SHALE GAS RESERVOIR In terms of the lithology of conventional reservoirs, these can be divided into three types, for example, clastic rocks, carbonate rocks, and other rocks, and most of the oil and gas accumulations occur in clastic and carbonate rocks. Shale is one of the most widely distributed sedimentary rocks, and globally accounts for about 60% of all sedimentary rocks. It is not only the important oilgenerating rock, but also provides excellent trap cover, and can even be thought of as an oil and gas reservoir. Compared with a conventional reservoir, the shale reservoir contains abundant organic matter and clay minerals. The pores provide nanoscale porosity, and thus have very low porosity and permeability. Accumulation of shale gas is determined by the degree of development of the shale pores and fractures. The pore permeability decreases continuously as burial depth increases and compactness is enhanced. Nevertheless, the existence of natural cracks will improve the accumulating properties of a shale gas reservoir. In other words, because of the compactness of shale reservoirs, the resistance to natural gas is much higher than in the conventional reservoir. The wells can only be exploited after reservoir reconstruction is applied. This section uses various test methods, such as the mercury intrusion method, gas adsorption and pulse decay method, in combination with direct observation under the light microscope and SEM, to analyze the types of accumulation spaces, the development characteristics, porosity, and micropore structure of the Yanchang Shale in the south of the Ordos Basin, in order to discuss the factors influencing the development characteristics of the shale pores.

1  SHALE ROCK STRUCTURAL MODEL Different from the conventional oil and gas reservoir, the shale gas reservoir contains both inorganic minerals and a volume of organic matter. The organic matter exists mainly in the form of solids and pore fluid that is closely related with the maturity of organic matter. The immature organic matter is mainly the solid organic matter, as well as formation water. The solid organic matter is distributed between the mineral particles, whereas the fluid fills the pore space. If the maturity of organic matter is relatively high, some organic matter will transform to liquid hydrocarbon, which migrates into the pores. During this process of transformation, massive isolated pores or connected micropores are formed inside the organic matter as shown in Fig. 3.19. Therefore, the shale rock can be divided into two constituent parts of inorganic matter and organic matter. The organic matter comprises a small fraction of the shale volume, of which most exists in the form of solid maceral. The inorganic matter in shale can be analyzed, as in all the rocks, using X-ray diffraction in order to identify the minerals. The inorganic minerals in shale usually have hydrophilic properties and massive clay-bound water is often generated in the pores

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FIGURE 3.19 SEM image of solid organic matter in shale.

of shale. If the pore throats in shale are very fine, the water membrane on the surface of the pores will develop very strong tension and form capillary-bound water. However, the larger pores in shale are usually filled with formation water or oil and gas. Based on the aforementioned understanding, the physical model of the shale rock strata proposed in this book is shown in Fig. 3.20. Compared with the conventional solid rock model, the solid volume model includes the solid organic matter, which is deemed to be one part of the rock matrix. The solid organic matter has specific physical and chemical properties, such as low sonic speed, low bulk density and high hydrogen content. Therefore, the solid organic matter has the logging response of high sonic AC, low DEN and high CNL. These latter logging responses result in an increased calculated

FIGURE 3.20 Physical volume model of shale rock strata.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.21 Rock matrix model of the Yanchang Shale. (A) Pie diagram showing statistics of mineral components in the Yanchang Shale. (B) Diagram of shale strata matrix model.

porosity, although the RT log readings do not fall accordingly. As the maturity of organic matter increases, the gas saturation of organic matter rises, and thus results in an increased resistivity of the shale. For the practical application of the volume model for the shale strata, the solid matrix or matrix model and the pore volume model can be discussed separately. It can be determined from the results of the experimental tests on the core samples of the Yanchang Shale that the inorganic minerals in the shale strata are mainly clay, quartz, feldspar, and some heavy minerals (Fig. 3.21A). The correlation between the characteristics of clay minerals distribution and the rock matrix particles has an important influence on the properties of shale. Different clay minerals have different physical and chemical properties, and thus also exert different influences. The distribution of clay minerals in the shale strata is approximately layered, while the distribution of solid organic matter is approximately as random blocks. Thus, the volume average method can be used to propose a model to calculate the solid matrix of shale, which is shown in Fig. 3.21B. Based on the aforementioned volume model of shale strata, the void spaces of shale pores are divided into two parts. Part 1 is the pore volume of inorganic minerals, where the pores can be further decomposed to bound-water porosity

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FIGURE 3.22 Diagram of the pore volume model of shale.

and unbound fluid porosity. The bound-water porosity mainly consists of claybound water and capillary-bound water. The unbound fluid pore space mainly contains formation water and some residual oil and gas. Part 2 is the pore volume of organic matter, which are mainly occupied by the adsorbed gas and free gas. The model of shale pores as established is shown in Fig. 3.22. The distribution of clay minerals in shale strata is mainly in the form of scattered particles, thin films, and cross-bridges. For example, kaolinite is distributed in the form of scattered particles, chlorite, and smectite are in the form of thin films, and illite is in the form of cross-bridges. The original intergranular pores of clay in the form of scattered particles are partitioned into micropores by many loose clay particles, and hence the connectivity of rock pores are reduced. The form of thin films will reduce the effective radius of pores, and often lead to blockages of the pore throats. The cross-bridge will reduce to a great extent the connectivity of rock pores, and there are many isolated pores in the clay minerals. These isolated pores have no functional role in the migration of natural gas. Only those connected pores can provide the ability to migrate natural gas, and such pores are referred to as the effective porosity. This effective porosity excludes partial pore space that cannot play a role as gas flow channels, such as various pore spaces of bound-water. The total porosity of the shale strata can be acquired using the formation welllogging, but the routine logging interpretative model does not consider the volume fraction of organic matter. In this book, we propose to define: (1) the effective porosity as unbound fluid space in the pore space of inorganic matter and the pore space of organic matter; and (2) the bound-water porosity as the space occupied by adsorbed gas, and some nonconnected pore spaces as isolated pores. When the aforementioned models are used to calculate the effective porosity of shale, the models need to thoroughly incorporate the core test properties, TOC, and well-logging data. Because the core analysis data and well-logging data are completed in different collection states with different instruments, the sampling precision of the core analysis data and well-logging profiles are different. Thus, the various data sets need to undergo the necessary pretreatment prior to synthesis and further analysis. Because of the experimental test data from actual samples, the parameters, such as TOC, kerogen volume ratio, formation-bulk density, matrix density, and kerogen density can be inverted to obtain the effective porosity of shale, and so forth.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 2  PETROLOGIC CHARACTERISTICS OF SHALE MINERALS Shale mineral assemblages usually consist of quartz and clay minerals as the main components, where the latter include kaolinite, illite, chlorite, smectite, and mixed layer illite-smectite, etc. Both quartz and clay minerals comprise most of the bulk composition of shale. In addition, the shale also includes carbonate minerals, such as calcite and dolomite, as well as the other minerals, such as feldspar, pyrite, and rare gypsum. If the contents of brittle minerals, such as quartz, are high, this will be favorable for the formation of fractures by late fracturing. Shale tends to undergo corrosion to form dissolution pores, where the strata have high contents of the carbonate mineral calcite. There is a relationship between the contents of clay minerals in the shale reservoir and the adsorbed gas volume, while the main factor is that the swelling clay minerals of illite, kaolinite, and smectite are unfavorable for the late fracturing in the reservoir. Quartz is the primary brittle mineral in shale. If there is high content of brittle minerals, such as quartz in the shale, the brittleness of the shale is rather high, and the shale will be readily affected by external forces to form natural fractures or induced fractures. Nelson found that feldspar and dolomite are also brittle components in black shale. Li et al. (2009a) found that not all the apparently excellent hydrocarbon rocks possess an economically exploitable value. Only the brittle shales with a low Poisson’s ratio, high elastic modulus, and rich in organic matter are the main focus of shale gas development. The quartz content can be calculated from whole rock chemical analysis, and also can be acquired using elemental-capture spectroscopy (ECS) logging. Clay minerals are the main components of shale, and together with quartz make up most of the mineral structure of shale. The clay minerals in shale can be divided in terms of origins into authigenic clay minerals and allogenic clay minerals. The authigenic clay minerals refer to the minerals that formed in the shale during the diagenetic stage after deposition, for example, authigenic kaolinite and authigenic chlorite. The allogenic clay minerals are mainly detrital minerals from the lacustrine sedimentary source area, and the mineral components are related to the types of rocks in the source area, that is, sedimentary provenance. The clay minerals are an unstable factor during shale reservoir reconstruction. In particular, if the content of clay minerals consists of water-sensitive minerals, such as kaolinite, then dissolution of the clay minerals tends to result in blocked fracture channels that are impervious to the transit of shale gas, and thus affect the output of shale gas. From this viewpoint, the higher the content clay minerals in a shale reservoir, the less favorable for reservoir reconstruction. In addition, the existence of clay minerals tends to give rise to collapse of the well wall during drilling. The collapse of the well wall is due to the dissolution of clay minerals by water, and is a major problem in shale reservoir completion. The lithology of the Yanchang Chang 7 Shale in the south of the Ordos Basin are mainly black, dark gray, dark gray, dark gray oil shales interbedded with

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FIGURE 3.23 Drill core showing fracture of the Yanchang Chang 7 Shale. (A) Well YY9. (B) Well YY4.

dark mudstone, carbonaceous mudstone, siltstone, silty mudstone, or muddy siltstone. The siltstone in the shale formation can occur in the form of laminae, strips, lens or wisps (Fig. 3.23). The detrital clasts in shale are mainly quartz, feldspar, mica, small amount of eruptive acidic volcanics, metamorphic rocks, and others. The mud-iron and calcium are distributed evenly among the particles with layered, stripped, or porphyritic aggregation. In addition, there are also some iron oxides, and trace pyrite and carbonates (e.g., siderite), commonly occurring as cements. Quartz, mica, and organic matter have an oriented distribution parallel to bedding, along with some coal, carbonaceous strips, and plant debris. There are diagenetic phenomena, such as authigenic enlargement of quartz and feldspar, feldspar and calcite dissolution, as well as pseudomorphism of feldspar by sericite and kaolinite, and so forth. In order to analyze the complete mineral composition of the shale, 23 shale samples were crushed to 200 meshes and dried for 5 h at 50°C. The samples were analyzed by XRD, with the following operating conditions: BRUKER D8 ADVANCE model X-ray diffractometer using Cu (monochrome) radiation; working voltage of 40 kV; working current of 30 mA; scanning angle of 2θ = 3–85 degree; slit of 1 mm; and scanning rate of 4 degree/min. The results of the analysis indicate that the main minerals in the Yanchang Chang 7 and Chang 9 Shales in the Ordos Basin were mainly clay minerals, quartz, and feldspar. In addition, there is also some carbonates and pyrite (Fig. 3.24). It can be seen from comparative analysis that the mineral components of the Yanchang Shale in the south of the Ordos Basin exhibit strong inhomogeneity. Even within the same formation in the same well, the mineral compositions of samples from different depths also exhibit large differences. For example, the two sampling depths for YY7-1 and YY7-2 differed by 1 m, yet there are large differences in the values of mineral compositions. The mineral compositions of YY7-1 consist of 39% quartz, 19% feldspar, 31% clay minerals, whereas YY7-2 consists of 44% quartz, 8% feldspar, the content of Chang stone is 8 and 44% clay minerals (Fig. 3.24A). The quartz contents of the Chang 7 and Chang 9 Shales in the southern regions of the Ordos Basin mainly vary in the range of

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.24 Triangular diagram of mineral composition. (A) Yanchang shale. (B) Domestic and overseas shale

20%–42%, with an average of around 32.3%, which is lower than that of the Barnett Shale and of Paleozoic (Cambrian - Silurian) marine shales in South China (Fig. 3.24B). The feldspar contents are relatively high and normally vary in the range of 10.0%–33.9%, with an average value of 24.2%, and are higher than that of feldspar of the Yanchang Formation in the US region. The clay mineral contents vary greatly, but mainly vary in the range of 21.0%–64.08%, with an average value of 40.4%, which is higher than that of the Barnett Shale or the Paleozoic (Cambrian–Silurian) lacustrine shales in China. The sum of the contents of the brittle minerals, quartz, feldspar, carbonate, and pyrite gives an average of 58.2%. The rock mineral components, excluding organic matter, in the Yanchang Chang 7 Shale of the Ordos Basin are mainly quartz and clay minerals. In addition, there are also minor feldspar, carbonate, and pyrite (Fig. 3.25A). The content of quartz is in the range of 15%–56%, with an average of 31.1%, and the content of clay minerals is in the range of 20%–77%, with an average of 44.5%. The clay minerals are mainly illite, mixed layer illite-smectite, and trace amounts of chlorite (Fig. 3.25B). The illite content of clay minerals varies in the range of 11%–48%, with an average of 26%. The mixed layer illite-smectite content of clay minerals varies in the range of 29%–87%, with an average of 52.4%, whereas the smectite content in the mixed layer illite-smectite is an average of 19.1%, and the average content of chlorite is 19.2%. The rock mineral components, excluding organic matter, in the Yanchang Chang 9 Shale in the southern region of the Ordos Basin are mainly quartz and

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FIGURE 3.25 Histograms of mineral compositions in the Yanchang Chang 7 Shale. (A) Characteristics of main mineral compositions. (B) Characteristics of clay mineral compositions.

FIGURE 3.26 Histograms of mineral compositions in the Yanchang Chang 9 Shale. (A) Whole-rock mineral and (B) clay mineral.

clay minerals. In addition, there are also minor feldspar, carbonate, and pyrite (Fig. 3.26). The content of quartz is in the range of 23%–45%, with an average of 31.5%, and the content of clay minerals is in the range of 28%–62%, with an average of 47.5%. The clay minerals are mainly illite and mixed layer illitesmectite, and trace amounts of chlorite (Fig. 3.26). The illite content of clay minerals varies in the range of 12%–44%, with an average of 25.9%. The mixed layer illite-smectite content of clay minerals varies in the range of 32%–79%, with an

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.27 Schematic diagram of shale fracture—pore network (according to Pollastro et al., 2007). (A) Fractured mudstone and (B) mudstone without fracture.

average of 58.5%, while the content of smectite in the mixed layer illite-smectite is an average of 18.6%, the average content of chlorite is 14.8%. The analysis of mineral compositions indicates that the shale in this area has been in the Phase A of mesogenetic stage. It can be seen from the contents of clay minerals that the contents of mixed layer illite-smectite are the highest, followed by illite and chlorite. The clay minerals have a very strong influence on the adsorption properties of natural gas, and a study by Lu et al. (1995) revealed that illite has rather strong methane-adsorbing capacity. Recent studies indicate that both illite and smectite have relatively strong methane adsorbing capacity, where the methane adsorption by illite (∼3 mL/g) is slightly higher than that of smectite (∼2 mL/g). However, kaolinite has relatively low methane adsorption capacity, roughly a third of that of illite (Ross and Bustin, 2009), and this variation in the methane adsorption capacity of minerals is mainly determined by the distribution of mineral pores. Clay minerals have significant effects on hydrocarbon generation. Regardless of the conditions, organic compounds will be readily adsorbed to the surface of clay minerals. Clay minerals, such as smectite and illite, have a very significant influence on the structure of the hydrocarbon molecule (Huizinga et al, 1987; Johns and McKallip, 1989; Tannenbaum and Kaplan, 1985; Tannenbaum et al., 1986). Kerogen mixed with smectite will generate a volume of C1–6 hydrocarbon gases that are five times that generated by kerogen alone. In the case of illite, the volume of generated C1–6 hydrocarbons is relatively low, but still higher than that generated by kerogen alone (Tannenbaum and Kaplan, 1985). The results of studies by Schettler, et al indicate that the adsorbed methane in shale is mainly distributed on the surface of the clay mineral illite, followed then by being adsorbed on kerogen. The results of the study by Lu et al. (1995) demonstrate that the presence of illite in the clay minerals is especially important to the adsorption effect of shale gas in shales with low organic carbon content.

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Lacustrine Shale Gas An increase in the contents of carbonate and quartz detrital clasts in shale can weaken the adsorption capacity of shale-to-shale gas. Meanwhile, it also reduces the porosity of shale, resulting in a decrease in accumulation space for free shale gas in the shale. The high content of clay minerals is a feature of shale rich in organic matter. For example, the clay mineral contents of the Bossier Shale in the USA is higher than 70%; the clay mineral contents of the Woodford/Barnett Shales in Ohio are in the range of 15%–65%, where the clay mineral contents in the siliceous Barnett Shale is usually lower than 50%. From the perspective of shale-gas exploitation, the mineral contents in the Yanchang Chang 7 and Chang 9 Shales in the Ordos Basin is appropriate, particularly the contents of quartz and feldspar, which are in the range of 20%–60%, and which is favorable for the application of exploitation technologies, such as fracturing. The high contents of clay minerals, especially the high contents of illite and smectite, with their strong adsorption capacities, will be favorable for improving the adsorption properties of the shales and hence in the storage of adsorbed gas.

3  PORE TYPES AND STRUCTURE CHARACTERISTICS Shale-gas reservoirs feature low porosity and ultralow permeability, as well as strong inhomogeneity. Shale matrix pores and fractures (shown in Fig. 3.27) constitute the main reservoir space for free gas in shale. With the increase in burial depth, pressure increases progressively, mechanical compaction increases, and pores are compressed continuously, resulting in declining pore-throat radii and permeability. With the increase in thermal maturity, kerogen is degraded into oil-gas, and new pores are produced between particles, which improve shale pore permeability. The modes of occurrence of shale gas are varied, but mainly in the free state and adsorbed state. Shale gas in the free state mainly occurs in rock pores and fractures, whereas shale gas in the adsorbed state is adsorbed by clay mineral particles, kerogen particles, and pore surfaces. Pores and fractures widely developed in shale are places for shale gas occurrence, because the extent of the shale pore development determines the amount of shale gas reserved, whereas fractures are the main channels in the shale gas reservoir for gas flow, thus determining its production capacity.

3.1 Pore 3.1.1  PORE CLASSIFICATION Shale reservoir space can be divided into the two categories: pores and fractures. Pores are mainly divided into three categories: (1) primary intergranular pores, (2) secondary corrosion pores; and (3) organic matter hydrocarbon-generating pores. Pores can be divided into micropores (<2 nm), mesopores (2–50 nm) and macropores (>50 nm), of which pores of more than 100 µm are ultramacropores (shown in Fig. 3.28).

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.28 Shale pore classification scheme.

3.1.1.1  Primary Intergranular Pores Primary intergranular (intercrystalline) pores developed in shale mainly include clay mineral intergranular pores and detrital particle intergranular pores. Clay mineral intergranular pores refer to pore space enveloped by clay minerals, of which two shapes can be observed under the resolutions scale of the SEM. The first is equant (Fig. 3.29A), which can either be a residual pore of a circular block of clay preserved when settled in standing water, or an intergranular pore formed by clay mineral agglomeration under strong hydrodynamic force, as its pore shape is quite smooth, and chaotically distributed, mostly in macropores. The second is of prolate type (Fig. 3.29A), which exhibits a threadlike shape, and is subjected to compaction and distributed along the clay mineral bedding orientation. The pore size range is mostly in the tens of nanometers, and thus belongs to mesopores, the most common pore type of clay mineral intergranular pores. Detrital particle intergranular pores are pore spaces formed by accumulation of rigid detrital particles, such as quartz and feldspar. Such pores are mostly developed in silty laminae in shale. The pore shape is an irregular polygon, where the pore size is mainly that of micron-sized macropores, some of which can even reach tens of microns, and can be observed under an ordinary light microscope (Fig. 3.29B). As intergranular pores are often filled with fine matrix and cement, most residual intergranular pores consist of intercrystalline pores

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FIGURE 3.29 SEM images of shale pore characteristics in the Yanchang Shale. (A) Clay mineral intergranular pores (equant, prolate), well YY8, 1522.8m; (B) micron-sized detrital particle intergranular pores in argon ion polished section of sandy lamina; (C) detrital particle intergranular pores filled by quartz cement; (D) clay mineral-filled detrital particle intergranular pores; (E) detrital particle intergranular pores in argon ion polished section; (F) particles and corrosion pores inside clay particles in argon ion polished section; (G) siliceous cement and quartz particle corrosion pores in argon ion polished section; (H) feldspar corrosion pores in argon ion polished section; (I) shale organic maceral hydrocarbon-generating pores; (J) shale organic maceral hydrocarbon-generating pores.

in cement after the original intergranular pores are filled with quartz, authigenic clay minerals (Fig. 3.29C), and clay mineral intergranular pores (Fig. 3.29D), which greatly reduce the pore volume. However, subject to mechanical support from the surrounding detrital particles, a lot of the intergranular pores are developed in interstitial material, such that the residual detrital particle intergranular pores are mainly mesopores to macropores.

3.1.1.2  Secondary Corrosion Pores Secondary pores formed in shale by corrosion are very common in the sandy laminae, mainly developed in feldspar particles (Fig. 3.29E), and interstitial matrix material, including clay and siliceous cement (Fig. 3.29F). Pores are also occasionally seen in quartz particles, with authigenic clay minerals and hydrocarbons. Secondary corrosion pores include intergranular corrosion pores, intragranular corrosion pores and cement corrosion pores and mold pores, but

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 mainly intergranular corrosion pores. Intergranular corrosion pores have corrosion along the particle edges, often exhibiting embayment-type corrosion edges, with varied pore shapes, which may be of elongate type or irregular polygon type. Intragranular dissolved pores are mostly of the nanometer scale, from mesopores of tens of nanometers to mostly macropores of hundreds of nanometers. The corrosion of some feldspar particles is very intense, which no longer retain their original particle shape, and form corrosion macropores (Fig. 3.29G).

3.1.1.3  Organic Matter Hydrocarbon-Generating Pores Organic matter hydrocarbon-generating pores in shale refer to the pore space in kerogen produced during the hydrocarbon-generating process. Hydrocarbongenerating pores in organic maceral can be observed in fresh fractures in the Lijiapan Shale of well YY1 under the SEM (the yellow frame area in Fig. 3.29H). As the area close to the pores is affected by hydrocarbon generation, the density becomes relatively low, and the color of the organic maceral becomes deep. The pore diameter size range of organic matter hydrocarbon-generation pores is 1–10 µm, which belongs to macropore size range (Fig. 3.29I). The shape of these pores is mainly round, as well as triangular, polygonal, and irregular strips, and these pores are often distributed in clusters, mainly in the area of the kerogen edge. Organic matter pores of the Yanchang Chang 7 and Chang 9 Shales are less well developed, which is related to the low degree of thermal evolution of the shales.

3.1.2  LACUSTRINE SHALE PORE STRUCTURE CHARACTERISTICS Nonconventional natural gas (dense gas, shale gas, and coal-bed gas) reservoirs have little pore structure, and those pores are concentrated around the 10 nm scale, whose characteristics are thus not readily observed nor explained. At present, common research methods used to study shale pore structures can be divided into two methods: (1) direct observation and description methods, and (2) physical test methods. The direct observation and description methods include: (1) the pore casting thin section method, (2) SEM imagery method, and (3) argon ion polishing plus backscattered electron imagery method. The physical test methods include: (1) the mercury intrusion method, (2) gas adsorption method (CO2, N2), and (3) pulse attenuation method (Fig. 3.30). The porecasting thin-section method, the SEM method, and the argon-ion polishing coupled with backscattered electron (BSE) imagery methods can be used to examine the pore types, sizes, and pore structural characteristics. The mercury intrusion method, gas-adsorption method, pulse-attenuation method, and helium-testing hydrometer method can all be used for quantitative testing of pore distribution, specific surface, porosity, permeability, and so forth, to effectively represent the heterogeneity of the shale samples. It was determined by an observation on the Barnett Shale reservoir that its reservoir space mainly consists of nanometer-scale pores, that the pore cross-sections are irregular, ellipsoidal, and bubble-like, that their diameters are generally between 5 and 750 nm, and that their pore throat diameters are mainly 5–15 nm. The pores

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FIGURE 3.30 Diagram of effective size ranges of methods in evaluating nonconventional natural gas reservoir porosity and pore distribution characteristics.

are mainly intragranular pores, intergranular pores, and thermal maturity contraction pores formed in organic matter during the advanced pyrolysis process. A small fraction comes from intergranular pores formed by framboidal pyrite recrystallization and intergranular micropores formed by silicified-recrystallization of fossils (Loucks et al., 2009), with the porosity as high as 10%–14%, but generally in the range of 3%–5%. The average pore diameter of shale in the Yanchang Formation in the southern part of the Ordos Basin is mainly distributed in the range of 6–7 nm, with the average value of 7.2 nm (Fig. 3.31), and hence are mainly mesopores. Based on the distribution of pore diameters in shale samples from the Chang 7 to 9 in well LP171, the pore diameters form a single peak, with the diameter mainly distributed between 3 and 5 nm, and hence are mainly mesopores (Fig. 3.32). Analysis of shale pore type in the Yanchang Formation indicates that the shale pore type of the Chang 9 is mainly mesopores, whereas micropores are not well developed (Fig. 3.33). The mesopore, macropore, and micropore volumes

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.31 Histograms of pore diameters in shales of the Yanchang Formation of the Ordos Basin.

FIGURE 3.32 Plots of distributions of pore diameters in shales from the Chang 7 to 9 in well LP171. (A) Chang 7, 1729 m, (B) Chang 7, 1730 m, (C) Chang 7, 1780 m, (D) Chang 8, 1827 m, and (E) Chang 9, 1862 m.

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FIGURE 3.33 Bar chart of reservoir pore structure in the Chang 9 Shale of the Yanchang Formation.

account for 77.33, 18.60, and 4.06% of the total pore volume, respectively. The average pore diameter of shale in the Chang 9 of the Yanchang Formation is 16.1 nm, with a median diameter of 8.0 nm, while the total pore volume is in the range of (2.5–9.8) × 10−3 mL/g, with an average of 7.8 × 10−3 mL/g (Fig. 3.33). The shale pore type of the Chang 7 of the Yanchang Formation is mainly mesopores, where micropores are not as well developed (Fig. 3.34). Mesopore, macropore, and micropore volumes account for 73.72, 22.16, and 4.12% of the total pore volume, respectively. The average pore diameter of shale in the Chang 7 of the Yanchang Formation is 23.3 nm, with median diameter of 11.7 nm, whereas the total pore volume is in the range of 2.6 × 10−3 to 1.2 × 10−2 mL/g, with an average of 7.1 × 10−3 mL/g (Fig. 3.34). Clay mineral and brittle mineral contents in shale of the Yanchang Formation have some effect on pore development, but it is mainly reflected in the effect

FIGURE 3.34 Bar chart of reservoir pore structure in the Chang 7 Shale of the Yanchang Formation.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.35 Crossplots showing correlation between total amount of clay and pores in shale of the Yanchang Formation.

FIGURE 3.36 Crossplots showing correlation between illite and mixed layer illite-smectite contents and pore in shale of the Yanchang Formation.

on mesopores and macropores, while its correlation with the micropores is not apparent. It can be determined from the test results that show mesopore volume, macropore volume, and total pore volume (mainly as mesopore volume) in shale are negatively correlated with the total clay contents (Fig. 3.35). The correlation of the contents of illite and mixed layer illite-smectite, the main clay minerals, with mesopore volume and total pore volume are consistent (Fig. 3.36). The quartz content is in direct proportion to the macropore volume, indicating that an increase in quartz is favorable for the development of macropores. However, the relationship between quartz content and the total pore volume is not obvious, and this may be because the lacustrine shale of the Yanchang Formation contains a lot of feldspar in addition to quartz. By combining quartz, feldspar, and carbonate minerals as brittle minerals for convenience here, it was possible to ascertain whether the brittle mineral contents and mesopore volume, macropore volume, and total pore volume exhibit a positive correlation (Fig. 3.37). The results indicate that an increase in these brittle minerals is favorable for shale mesopore development. It can be determined from Fig. 3.38 that the TOC in the shale is positively correlated with mesopore volume, macropore volume, and the total pore volume, but do not have a clear relationship with micropore volume. This indicates that an increase in organic matter is conducive to pore development in lacustrine shale of the Yanchang Formation.

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FIGURE 3.37 Crossplots showing correlation between brittle mineral contents and pore volumes in shale of the Yanchang Formation.

FIGURE 3.38 Crossplots showing correlation between TOC and pore volumes in shale of the Yanchang Formation.

3.2 Fractures Fractures not only provide reservoir space for shale gas, but also provide a migration path for shale production. The extent and scale of fracture development are the main factors affecting shale gas contents and shale gas accumulation, determining shale permeability, controlling extent of shale connectivity, further controlling gas-flow rate and gas-reservoir-production capacity. The fractures can be divided into structural fractures and diagenetic fractures, according to the fracture genesis. The former are fractures related to structural stress, which are generally large, and are thus mainly macro-fractures. The latter are formed during diagenesis, which are smaller in scale, and are thus mainly microfractures.

3.2.1  FRACTURE CLASSIFICATION Based on previous studies, there are mainly structural fractures (tensile fracture and shear fractures), bedding fractures, bedding surface sliding fractures, diagenesis shrinkage microfractures and organic matter evolution abnormal pressure fractures.

3.2.1.1  Structural Fracture Structural fractures refer to those formed due to a local structure or fractures associated with a local structure, which are mainly controlled by crustal stresses and closely related to structural deformation. Its orientation, distribution, and deformation are related to local structure formation and development,

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 and generally at a high angle or perpendicular to the bedding plane, which can crosscut or bypass brittle minerals. Structural fractures are the most common, and thus principal fracture type in shale. Based on differences in their mechanical properties, fractures are divided into tensile fractures and shear fractures.

3.2.1.2  Bedding Fractures The bedding fractures are major pores and fissures between parallel bedding surfaces with planar partings, which are formed by sedimentation. They are generally the product of strong hydrodynamic conditions, consisting of a series of thin shales. The laminated structure of the shale is an interface with weak mechanical properties, which are easily eroded, and it is this interface that forms the laminated fissure of shale, which is the most basic fracture type in shale.

3.2.1.3  Bedding Surface Sliding Fractures Bedding surface sliding fractures refer to fractures with apparent signs of slippage, which are parallel to the shale bedding surface, and similar to the laminated bedding fissures of shale, is also one of the basic fracture types in shale. The relative slippage occurring on the shale bedding surface is mainly related to the difference in the extension rate or compression rate parallel to the bedding surface during the rock formation process. The bedding surface structure is the basic rock structure of shale, and is also the weakest mechanical structure, and whether in an extensional or compressional basin, the bedding surface slippage fracture is the most basic fracture type in shale. The bedding surface sliding fracture generally has a large amount of flat, smooth surface or surface with scratches or steps, which cannot easily be closed underground. The proportion of this detachment fracture is in the high percentiles in dark shale. Wells in shale gas basins in the USA also indicate that the detachment fracture and related extension, and the compression fractures, are more likely to occur in black shale rich in kerogen.

3.2.1.4  Diagenetic Shrinkage Microfractures These fractures correspond to the expansion or tension fractures that accompany total rock volume shrinkage at the early stages of diagenetic stage. Shale may easily form fractures due to clay mineral dehydration or phase changes causing volume reduction or shrinkage, which may be rectangular or in a net shape. Diagenetic shrinkage fractures include syneresis fractures and mineral phase change fractures. Diagenetic shrinkage fractures are observable when the muddy intercalations of shale and horizontal beds of marl are placed under SEM, which exhibit good connectivity and a large range in aperture size, some of which are filled. Generally, shale with high siliceous content during sedimentation will exhibit contractions due to chemical changes during diagenesis, thus forming widely distributed diagenetic shrinkage microfractures (Zhang and Yuan, 2002).

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Lacustrine Shale Gas 3.2.1.5  Organic Matter evolution Abnormal Pressure Fractures Organic matter evolution abnormal pressure fracture refers to fractures formed during thermal evolution, which produces local abnormal pressure, creating fractures. Organic matter evolution abnormal pressure fractures are universally developed in carbonaceous shale with a high organic carbon content. This kind of fracture is irregular along the fracture surface, does not form a system, and is mostly filled with organic matter. Underground overpressure microfractures in argillites are generally distributed to a certain depth vertically and width horizontally (Zhang and Yuan, 2002).

3.2.2  OUTCROP PROFILE OBSERVATION Observations of the outcrops of the Yanchang Formation at Zhangjiatan and Yanhe in the Ordos Basin have found that the fracture (joint) system in the Yanchang Formation has the following characteristics: (l) developed two joint system planes oriented NW and almost EW (shown in Fig. 3.39), which commonly form a X-type conjugate shear joint system in plan, which is the result of the regional horizontal shear; (2) sandstone, especially thick sandstone, has developed a vertical fracture and high-angle fracture (joint) system, as well as underdeveloped low-angle fracture and horizontal fracture; and (3) fractures in shale are mainly low-angle fractures and horizontal fractures, especially in black shale of the Chang 7 and Chang 9, where bedding fractures are developed.

FIGURE 3.39 Field outcrop photographs of shale of the Chang 7 of the Yanchang Formation in the southern area of the Ordos Basin.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 3.2.3  CORE OBSERVATIONS Microfractures play an important role in improving the reservoir and migration properties of shale reservoirs with extremely low matrix porosity. This can not only increase specific surface and reservoir space, but can also improve adsorbed gas content and free gas content, provide an effective migration channel, and improve the reservoir effective porosity and permeability. Core observations also indicate that various fractures are universally developed in the dark shale of the Yanchang Formation, such as shear structural fractures, extensional structural fractures, detachment fractures, bedding fractures, interlayer fractures and abnormal pressure fractures, of which bedding fractures are the most common. 1. Shear structural fracture: From the mode of occurrence, it is mainly a vertical fracture or a high-angle fracture, which extends long distances. The fracture surfaces are planar, often with a certain set and orientation, many of which are unfilled with good effectiveness, whereas some are filled with calcite (shown in Fig. 3.40A–B). 2. Extensional structural fracture: The fracture surfaces area not planar, and the angle of inclination and degree of openness changes greatly but occur mainly in open fractures (Fig. 3.40C); 3. Detachment fractures: Most common fracture type in plastic thick shale, which is related to extrusion effects, unbalanced load of the overlying formation, as well as relative plasticity of mudstone. The fracture surfaces are smooth, often with scratches or mirror characteristics (shown in Fig. 3.40D–E), and are generally in the horizontal or medium-low angle of inclination. 4. Bedding fractures: Refer to fractures formed along the sedimentary bedding subject to various geologic processes, and are a common fracture type in shale (shown in Fig. 3.40F). Bedding fractures are not only good reservoir space, but also one of the migration paths of the shale reservoir fluid, which can effectively improve reservoir-accumulation and gasproductivity performance. 5. Interlayer fractures: Related to detrital sheet material or parting lamination existing in the bedding surface or laminated bedding, or fractures formed in the weak contact between the boundary of different lithologic character. These are caused by stress release during load reduction, subject to certain tensile properties, and make a contribution to reservoir porosity and permeability, mostly in the horizontal attitude (shown in Fig. 3.40G); 6. Abnormal pressure fractures: Also known as overpressure fracture, which are caused by shale undercompaction due to rapid sedimentation or formed by abnormally high fluid pressure due to clay mineral transformation, dehydration, hydrocarbon-generation, or pressurized hot water in a closed state. Abnormal pressure fracture in the southern area of the Ordos Basin have irregular shapes, and the fracture widths change widely, while bitumen gets into the factures (shown in Fig. 3.40H–I). As for the fractures in the dark shale of the Yanchang Formation, the bedding fractures assume a dominant role (shown in Fig. 3.40A), mainly in 10–12 cm (note:

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FIGURE 3.40 Photographs of well core fractures of the Yanchang Formation in the southern area of the Ordos Basin. (A) Black shale with vertical shear structural fracture, filled with calcite, well YY7, 1143.71m, Chang 7; (B) black oil shale with a group of parallel shear structural fracture, well YY4, 1371.62m, Chang 7; (C) silty mudstone with tensile fracture, well 109, 868.60m, Chang 7; (D) black mudstone with detachment fracture, with scratches, well YY1, 1532.93m, Chang 9; (E) black mudstone with detachment fracture, with mirror characteristics, well YY1, 1338.43m, Chang 7; (F) black shale with bedding fracture, well YY1, 1358.7m, Chang 7; (G) interlayer fractures developed at contact of mudstone and sandstone, filled with carbon, Well YY1, 1401.55m, Chang 7; (H) black mudstone with abnormal pressure fracture, filled with bitumen, well Hua 36, 1376.40m, Chang 7; (I) black mudstone with abnormal pressure fracture, see bitumen on fracture surface, well Hua 36, 1376.40m, Chang 7.

core diameter is 10–12 cm) (shown in Fig. 3.40B), mainly followed by 0–0.2 mm fractures with openness, 0.2–0.4 mm (shown in Fig. 3.40C) with 0 degree in terms of angle of inclination, followed by high angle fractures or vertical fractures of 70–90 degree (shown in Fig. 3.40D). Considered from the state of filling, these are mainly open fractures, accounting for 97.6% of fractures, while the remainder are filled with calcite, bitumen, or carbon (shown in Fig. 3.40E).

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 3.2.4  SHEET OBSERVATIONS A common light optical microscope was used to examine sheets of the shale rock taken from the Yanchang Formation in the southern area of the Ordos Basin, to study fractures of smaller size, low-angle fractures (shown in Fig. 3.41), and high-angle fractures (shown in Fig. 3.42) that are filled with cement, fractures are less than those of rocks. The fracture width is distributed around 10–50 µm with good continuity, and bypasses rigid particles when encountered in the shale (shown in Fig. 3.43). Cement in the fractures includes calcite and siliceous materials, where the former exhibits high interference colors under crosspolarized light, whereas the latter shows first-order gray interference colors. To

FIGURE 3.41 Histograms of statistical parameters of core fracture characteristic in shales of the Yanchang Formation in the southern area of the Ordos Basin. (A) Distribution frequency of fracture types. 94.2% of the shale fracture was bedding fracture; bedding fracture is the main fracture type in shale reservoir. (B) Distribution frequency of fracture length. 97% of the fracture length was distributed in 10–12 cm; fracture development scale is not large. (C) Distribution frequency of fracture aperture. 92.9% of the fracture aperture was distributed in the range of 0–0.2 mm. (D) Distribution frequency of fracture dip. 96.7% of the fracture dip was distributed in the range of 0–20 degrees, mainly low-angle fracture. (E) Distribution frequency of fracture filling. 97.6% of the fracture was unfilled, only a few fractures were filled with calcite, bitumen, and carbon.

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FIGURE 3.42 Photomicrograph of low angle fracture filled with siliceous cement, 50×, (−).

FIGURE 3.43 Photomicrograph of high angle fracture filled with calcite cement, 20×, (+).

further study the internal structure of diagenetic fractures in this work, an SEM was used to examine the fresh fractures of shale, and was also used on fractures cemented by calcite, where the interior cemented structure shows notable differences. Fractures can be divided into two types according to the extent of the cementation of the fracture. Of the fractures, filled by Poikilitic—even calcites or siliceous cements are well aggregated, with coarse crystallization and fully developed crystal shapes. The cementing mineral is mainly carbonate, specifically calcite, with lesser siderite visible locally, and with authigenic clay minerals occasionally filling the intergranular fractures (shown in Fig. 3.44). In this type of fracture, no residual bitumen is found along the developed edge, corrosion pores, mold pores, and intergranular pores. Another fracture type is filled by micritic calcite and clay minerals, the cementation of the fracture is loose,

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.44 SEM images of fractures cemented by calcite and siderite.

FIGURE 3.45 SEM images of fractures filled with micritic calcite, authigenic clay minerals.

and pores are developed in the cement (shown in Fig. 3.45). In these types of fractures, micritic calcite cement size is generally in the range of 5–10 µm. Fine authigenic clay mineral crystals (1–2 µm) fill between the calcite, and this intergranular cement is disorderly and its crystal forms are varied. Intergranular pores are well developed, and the element carbon is detected in the EDS spectrum, confirming that residual bitumen is filling between pores or mineral crystals lining the inside of the fractures. It is generally believed that shale gas developed in shale with strong hydrocarbon generation. Shale of the Chang 7 and Chang 9 in the Yanchang Formation from the southern area of the Ordos Basin, were examined under the fluorescence microscope, and it was found that fractures with fluorescence are very well developed in the shales. According to their fluorescence response, there are three kinds of bitumen filling the fractures: (1) carbenes or gelinito bitumen with brown or black fluorescence, (2) oily bitumen with bright yellow fluorescence (shown in Fig. 3.45A), and (3) oily bitumen with blue-white fluorescence (shown in Fig. 3.45B) but mainly in blue-white fluorescence. This indicates that a two-phase hydrocarbon filling occurs in fractures in shale. Fractures filled by

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FIGURE 3.46 Photomicrograph of bitumen-filling low-angle net fractures with yellow fluorescence, 10×.

FIGURE 3.47 Photomicrograph of bitumen-filling low-angle fracture with blue fluorescence, 20×.

bitumen are mainly low-angle fractures parallel to bedding, although fluorescence may also be observed in high angle fractures cemented by calcite. The size range of fractures filled by bitumen is much finer than that of mineral cemented fractures, which are generally 1–6 µm wide, when observed under the microscope. Bitumen-filled fractures have poorer continuity than that of the diagenetically cemented fractures, but the number of fractures developed is greater, and these fractures can traverse the whole sheet. Bitumen-filled fractures at the nanometer scale can be observed using an SEM. As shown in Fig. 3.48, a lowangle fracture of around 87 nm in width in a polished section of a silty lamina is found to be filled with bitumen using a combination of EDS spectrum and carbon X-ray dot map imagery. Detrital particle intergranular pores near the fractures are also found to be filled with bitumen. For this kind of nanometer

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.48 Low-angle fractures in sandy laminae in shale. (A) Photomicrograph of shale lamina with low angle fracture, 5×, (+). (B) Photomicrographs of net fracture in shale, 4×. (C) SEM image of characteristics of fractures in shale.

scale bitumen-filled fractures, the fracture size is finer compared with those observed in the fluorescence sheet, and its continuity is also poorer (Fig. 3.46). In addition, shale is also developed with unfilled fractures (shown in Fig. 3.47), which are mostly distributed parallel to the bedding and exhibit good continuity. Their widths are finer compared with cemented fractures and bitumenfilled fractures, mainly 1–2 µm. Micritic-sized diagenetic minerals form crystals perpendicular to the fracture wall, and the fractures extend very far with strong migration capacity. Intergranular fractures and fissures in mineral grains and detrital particles are often visible in shale and sandy laminae, and such fractures crosscut one another to form a fracture network, which constitutes a good pathway for oil-gas migration and hydrocarbon discharge.

3.2.5  FRACTURE DEVELOPING INFLUENCING FACTORS Compared with conventional natural gas, a shale gas reservoir’s economic yield largely depends on natural fractures. Natural fracture development in shale can improve its porosity and permeability performance significantly. Shale reservoir porosity can reach up to 10% in the natural fracture development zone, and the permeability may reach up to 0.001 µm3 (Gale et al., 2007). Rock fracture development is depends on external and internal factors, where external factors are mainly related to the hydrocarbon-generating process, formation pore pressure, anisotropic horizontal pressure, faulting and folding, whereas the internal factors mainly depend on the mineralogical characteristics of the shale (Long et al., 2011). Various scholars have conducted a lot of research on the factors influencing fracture development. It is generally held that the lithologic character, organic-carbon content and mineral composition are the important factors affecting fracture development (Hill and Lombardi, 2002).

3.2.5.1  Impact of Lithologic Character on Fracture Development The impact of lithologic character on the extent of fracture development is mainly reflected in rupture strength of different lithologies under the same

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Lacustrine Shale Gas stress. Shale with low a Poisson ratio and high Young’s modulus has low rupture strength and is very brittle, and thus may easily form a fracture. In general, shale with a high carbonate and siliceous content may easily rupture due to its high brittleness, whereas that with low carbonate and siliceous content exhibits obvious plasticity, and its extent of fracture development is relatively low (Long et al., 2009). Lithologic character differences also affect the development of bedding fractures, and shale with well-developed bedding has more microfractures than mudstone lacking bedding, which mainly reflects that organic matter strips or wisps contain a lot of microfractures (shown in Fig. 3.48). Although the rock does not show bedding with macro bedding fractures, such fractures can be seen under the microscope in the form of microfractures. Low-angle fractures are often developed in shale laminae near sandy laminae, and the greater the heterogeneity, the easier net fractures will form. This is possibly because fracture development is mainly dependent on the stress-distribution characteristics, where the existence of sandy laminae cause a nonuniformity of the stress distribution, causing shale laminae or small-scale sandy laminae to bear a relatively higher stress, and thus more likely to develop fractures. The results of observations on drill core from the Appalachian Basin indicate that detachment and related extension and contraction fractures are more likely to be developed in black shale rich in kerogen, rather than in gray shale with siltstone interbeds. The extent of fracture development in black shale is higher than the extent of fracture development in nearby gray shale, with high fracture frequency and shorter intervals, and the fractures generally terminating at the interface between different lithologies. Thin black shale is higher in organic carbon content than thick shale, and the extent of fracture development is also higher. Therefore, the extent of fracture development decreases with increasing shale-formation thickness.

3.2.5.2  Impact of Organic Matter Abundance on Fracture Development Research indicates that under the same mechanical conditions, the abundance of organic matter is one of the important factors affecting the development of microfractures in dark shale. Jarvie et al. (2003) proved through experiments that when shale has consumed 35% of the organic carbon content during hydrocarbon-generating evolution, shale pores may increase by 4.9%. Thus, the higher the initial organic carbon content, the more microfractures and micropores are produced during the hydrocarbon-generation process. Ding Wenlong et al classified the relationship between organic carbon content and the extent of fracture development in shale into four categories: (1) when the organic carbon content is less than 2%, the fracture development extent is poor; (2) when the organic carbon content is 2%–4.5%, the fracture development extent is moderate; (3) when the organic carbon content is 4.5%–7%, the fracture development extent is high; and (4) when the organic carbon content is greater than 7%, the fracture development is very high. Shale fracture in the southern area of the Ordos Basin also

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.49 Diagram with profiles of fracture development and mineral content for shale of the Chang 7, well LP177.

has similar characteristics, in which the higher organic carbon content results in more macro- and microfractures being developed. There is an overall positive correlation between the macrofracture linear density, sheet-surface fracture rate, and organic-carbon content (shown in Fig. 3.49). The impact of organic-carbon contents on the extent of microfracture development mainly reflects the distribution of the organic matter, in that the higher the contents of organic matter, the more defined the wisps, and the more readily microfractures are developed in the organic matter wisps or along their contacts (shown in Fig. 3.50).

3.2.5.3  Impact of Mineral Composition and Content on Fracture Development Shale mineral composition is very complicated, and statistical analysis confirms that a shale formation with a large amount of siltstone or sandstone interlayers is high in quartz content. Shale is also very brittle, which may easily result in natural fractures or induced fractures under external force, and brittleness is favorable for natural gas migration. Marine shales in the USA and in the south of China universally contain a highly brittle mineral content, with a relatively well-developed fracture. The impact of brittle minerals on fractures is mainly reflected in differences in the structural fractures. However, tectonic activities were weak in the southern area of the Ordos Basin, and faults and folds are not developed, such that the proportion of structural fractures is very low. The quartz content is also an important factor affecting fracture development, where a section of black shale rich in quartz is very brittle, and the extent of

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FIGURE 3.50 Crossplot of sheet surface fracture rate and TOC content in the Chang 7 Shale.

fracture development is stronger than in gray shale rich in calcite with greater plasticity. In addition to quartz, feldspar and dolomite are also brittle components in the section of black shale. Therefore, under the same tectonic conditions, accurate analyses of the shale lithologic character, color, thickness, and mineral compositions are key to accurately assessing the scale and extent of fracture development. As clay minerals have a high volume of micropores and high specific-surface area, clay mineral adsorption properties are relatively strong. With the increase in the contents of brittle minerals, such as quartz and carbonates in a shale formation, shale brittleness will increase, making shale rock formations more likely to form natural fissures and permeable fractures under an external force. The various fractures and fissures formed are favorable for shale gas migration in shale, but also increase the reservoir space in the shale for shale gas in the free state, and also contribute to reservoir fracturing during shale development. Fractures have a dual role in shale-gas accumulation, which can also be described as a double-edged sword. The extent of development and scale of fractures are the main factors affecting the amount of shale-gas accumulation, determining the extent of shale permeability and controlling shale connectivity, as well as further controlling gas-flow rate and gas-reservoir-production capacity. Fractures also determine preservation conditions in shale-gas reservoirs, because where fractures are developed, the preservation conditions of shale-gas reservoirs may be poorer and natural gas may be readily lost, have difficulty accumulating, or shale-gas reservoirs simply cannot form. Conversely, fracturing may be favorable to the formation of shale-gas reservoirs. In areas affected by fault activity, fractures in rocks can be quite developed near faults, and as a result of the effect of infiltration of meteoric water, shale-gas preservation conditions near areas of faults are very poor. For example, the production rates of natural gas are lowest in fracture-developed areas in the gas reservoir of the Barnett Shale in the Fort Worth Basin, and high-yield wells are basically distributed in areas where fractures are underdeveloped. The Fangshen 1 well in Qianzhong is located near the fault of the northern margin. Although the well has shale display, natural gas is also produced from a fracturing test of

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 black shale of the Niutitang group. However, as it is near to a natural fracture, it results in a low-gas content and the gas yield is limited after fracturing. Shale-gas basins currently under commercial exploitation in the USA contain fractures and folds formed on the rock surfaces after having experienced regional tectonic movements, and also have had effective unconformities formed after having experienced sea-level changes. These fractures and surface unconformities provide accumulation space for shale gas, as well migration paths for shalegas production. Due to the extremely low bedrock permeability in shale, open vertical faults or several sets of natural fractures can increase shale-reservoir yield.

3.3  Characteristics of Pore Diameter Distributions The pore diameter refers to the pore width or the distance between two walls of a slit pore. The pore diameter distribution relates to the pore volume distribution. Pore-diameter distribution methods are mainly divided into three categories: (1) differential distribution, (2) incremental distribution, and (3) integral distribution, and the pore-diameter distribution discussed in this section refers to its differential distribution. The differential distribution is a method describing the variation in pore volumes with pore diameter changes, and is mainly expressed using a dV(d) or dV(logd) graph. The dV(d) graph plots the volume increments divided by the difference between the upper and lower pore size of each increment, gives the volume change with the variation in diameter, and plots the midpoint to determine the increment pore diameter. The dV(logd) graph plots the volume increments divided by the difference between the logarithm value of the upper and lower pore diameter of the increment, gives the volume change with the variation in diameter, and plots the midpoint of the increment pore diameter. Points on the differential distribution graph do not correspond to the volume size directly, and a large change rate does not mean a large volume. Based on the pore classification of the International Union of Pure and Applied Chemistry (IUPAC), pores with diameters less than 2 nm are micropores, those with diameters between 2 and 50 nm are mesopores, and those with diameters greater than 50 nm are collectively known as macropores, while those with diameters greater than 100 µm are ultramacropores.

3.3.1  CHARACTERISTICS OF MACROPORE-ULTRAMACROPORE (ABOVE 10 µM) DIAMETER DISTRIBUTION Macropores and ultramacropores of more than 10 µm in shale of the Chang 7 of the Mesozoic Yanchang Formation of the Ordos Basin are not strongly developed, although large intergranular dissolved pores in the range of 10–100 µm are locally developed in sandy laminae in the shale, but in limited numbers. Such pores are mainly intergranular pores, corrosion pores, and microfractures (shown in Fig. 3.51, Fig. 3.52). For example, in a shale sample containing silty laminae from well Xin 55 (1055.56 m), macropores of more than 10 µm are developed. This kind of pore can be observed inside the shale sandy laminae and at the shale laminae boundary under the ordinary optical microscope (shown in

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FIGURE 3.51 Macropores coarser than 10 µm developed in the sandy lamina of shale and pore diameter logarithm differential distribution graph by sheet observation and mercury test (well Xin 55, 1055.56 m).

Fig. 3.51). The maximum pore diameter is in the range of 175–32 µm, and the pore walls have an embayment shape, with the residual detrital particle edge not fully corroded, and with dentate diagenetic mineral growth inwards. Additional pores other than the 10 µm intergranular corrosion pores are found when using the SEM to examine an argon ion polished sample of sandy laminae in shale, as shown in Fig. 3.52. The pore diameters reach up to 32 µm (shown in Fig. 3.52), and quartz cement is visible on the pore edges. The interior of the pores contains residue of feldspar detrital particles and authigenic clay minerals that are not fully corroded. From the mercury intrusion pore diameter differential distribution graph, the pore diameter distribution in the 10–200 µm range in a sample from well Xin 55 shows large intergranular corrosion pores with several independent peaks, and with poor connectivity (shown in Fig. 3.53A). The mercury penetration pore diameter differential distribution graph of most other samples have several

FIGURE 3.52 SEM images of intergranular corrosion pores coarser than 10 µm developed in a sandy lamina in shale.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.53 Pore-diameter logarithm differential distribution graph of argillaceous siltstone. (A) Mudstone and (B) Argillaceous siltstone.

continuous peaks within 10–200 µm range. However, under the supporting sheet, pores coarser than 10 µm or extensional pores are rarely observed. The mercury test results for argillaceous siltstone indicate (shown in Fig. 3.53B) that its pore diameters are mainly in the ultra-macropore range of more than 100 µm, and that pores of other diameter ranges are not as well developed. The porosity obtained by the mercury intrusion method is the highest compared with shale of other types, which are 4.02%–7.75%, respectively.

3.3.2  CHARACTERISTICS OF MACROPORE (50 NM–10 µM) DIAMETER DISTRIBUTION The high pressure mercury intrusion pore analysis method has a detection range of 7.5–75000 nm, and thus mainly analyzes pores with diameters in the macropore size range of 50 nm–10 µm, for which it therefore has good resolution. The 50 nm–10 µm pore diameter distribution is thus amenable to analysis by the mercury intrusion method. Using the SEM and the mercury intrusion method test analysis, the development characteristics of macropores in the range of 50 nm–10 µm are clearly dependent on the sandy content in shale. The results of SEM observations on samples from well YY4 indicate that its silty detrital particle content is low, and mainly consists of clay minerals, in which pores finer than 50 nm are mainly developed. However, a few pores coarser than 50 nm are also developed, mainly as intergranular pores in clay minerals. A few silty detrital particles are also visible in shale fracture samples from well YY4, and, therefore, the pore diameter logarithm differential distribution curve of 50 nm–10 µm pore size range fluctuates slightly (shown in Fig. 3.54), indicating that the number of pores developed greater than 50 nm is very low.

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FIGURE 3.54 Pore-diameter logarithm differential distribution graph by mercury intrusion method of pure shale sample, and SEM image of its fracture sample (well YY4, 1528.16 m).

3.3.3  CHARACTERISTICS OF MESOPORE (2–50 NM) DIAMETER DISTRIBUTION The nitrogen adsorption method is more effective than the mercury intrusion method for the pore diameter range of 2–50 nm, and therefore the nitrogen adsorption method can be selected to study the distribution of pores with diameters in the mesopore size range of 2–50 nm. Based on the results of the mesopore tests on 12 whole rock samples using the nitrogen adsorption method, and the pore-diameter differential-distribution graph curve shape, the pores can be divided into three types. The first type of pore is a single-peak type (shown in Fig. 3.55A), the volume of pores increases continuously with decreasing pore diameter. However, the volume of pores finer than 2.5 nm begins to decline after it reaches the peak at 2.5 nm. The second type of pore is a continuously increasing type (shown in Fig. 3.55B), in which the overall trend is that the finer the pore diameter, the greater the volume of pores developed. However, the trend remains stable or declines relatively at 2–3 nm, after which the pore volume continues to increase with decreasing pore diameter. The third type of pore is a transition type of the above two types (shown in Fig. 3.55C), in which a smooth, broad peak occurs within the 4–8 nm pore diameter size range, but declines relatively to a trough around 2.5 nm. After this, the volume of pores continues to increase with decreasing pore diameter. In combination with the specific pore volume data of pores in the 2–50 nm diameter size range, it was determined that the single-peak type accounts for the most pore volume among mesopore types, with a specific pore volume average of 1.93 cm3/100 g. The continuously increasing pore type accounts for the lowest pore volume, with a specific pore volume average of 1.49 cm3/100 g, whereas

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.55 Pore-diameter logarithm differential distribution graph of whole rock sample by nitrogen adsorption. (A) Single-peak type, (B) continuously increase type, and (C) transition type.

the pore volume of the transition type is between the above two types, with a specific pore volume average of 1.68 cm3/100 g. The preceding results in combination with the results of SEM observations on pores in the 2–50 nm size range, show that the mesopores in shale mainly include clay mineral intergranular pores and pyrite intragranular pores, as well as detrital particle cement intergranular pores developed in silty laminae, and intragranular corrosion pores (fractures) (shown in Fig. 3.56).

3.3.4  CHARACTERISTICS OF MICROPORE (LESS THAN 2 NM) DIAMETER DISTRIBUTION Due to the spatial resolution of SEMs there is a lower limit of observation using SEMs (i.e., typically 5–20 nm), such that micropores developed in organic matter and clay minerals are not observable using the SEM. Therefore, the carbon

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FIGURE 3.56 S|EM images of the characteristics of mesopores in shale. (A) Mineral intergranular pores, pore diameter 2–50 nm. (B) Framboidal pyrite intragranular pores. (C) Pores in sandy lamina in shale, pore diameter 2–50 nm.

dioxide adsorption test method is selected to analyze the characteristics of the micropore distribution in shale. The analysis indicates micropores finer than 0.45 nm, and those coarser than 0.8 nm, are relatively underdeveloped in shale, and that the micropore diameter in shale rock formation has a multipeak shape, with the peak volume of micropores at around 0.8 nm. The micropore distribution in silty laminae also has a multipeak shape, where the peaks are distributed relatively evenly, and there are less micropores than in shale laminae. However, the number of pores developed within the 0.3–0.6 nm and 0.8–1.5 nm ranges is greater than the number developed in shale laminae (shown in Fig. 3.57). An electron microscope, SEM, mercury-intrusion test, and nitrogen and carbon dioxide adsorption tests were used to examine the various pores (macropores, mesopores, and micropores) developed in shale. Macropores and ultramacropores occur as detrital particle intergranular pores, corrosion pores, and fractures, with the pore diameter mainly ranging from 0.1 to 1.0 µm. Mesopores are most developed in silty laminae, and occur mainly as clay mineral and detrital particle intergranular pores, cement intercrystalline pores, and corrosion pores. Mesopores show a continuous pore diameter distribution, where the finer the pore diameter, the greater the volume of pores. Compared with shale laminae, mesopores are more developed in sandy laminae, and the extent of this development is closely related to the silty detrital content. The pore diameter distribution characteristics of the sandy laminae are similar to that of micropores in shale, indicating that the supporting role of silty detrital particles are conducive to the preservation of micropores in clay minerals, while hydrocarbon generation will form a considerable number of micropores in organic matter.

3.4  Influencing Factors on Pore Volume Distribution The parameters most appropriate for representing shale pore volume in the physical property test methods must be selected. Also, the specific pore volume and specific surface test data from the mercury intrusion test, the nitrogen

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.57 Carbon dioxide adsorption pore diameter differential distribution graph of well YY7 shale. (A) 1142.94 m, (B) 1155.19 m, and (C) 1153.15 m

adsorption test and the carbon dioxide adsorption test must be integrated using the respective pore diameter range most reliable and effective for each method to analyze shale pore volume distribution characteristics and determine the influencing factors. The specific surface parameters obtained using the gas adsorption method can be used to describe shale pore-volume distribution characteristics. Langmuir’s single-layer adsorption model is selected for micropore specific surface area, as it reflects the surface area that carbon dioxide molecules occupy in pores during single-layer adsorption. The micropore wall spacing is small and the adsorption potential energy is high, mainly resulting in gas adsorption. Therefore, the greater the specific surface area encompassed by micropores, the greater the micropore volume, such that micropore specific surface parameters can be used to indicate micropore specific pore volume. On the other hand, the measured specific surface area and the measured specific pore volume of 2–300 nm mesopore-macropores exhibit a strong positive correlation (shown in Fig. 3.58), and therefore carbon dioxide and nitrogen adsorption specific surface data can be

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FIGURE 3.58 Crossplot showing correlation between 2 and 300 nm mesopore-macropore specific surface and specific pore volume of whole rock samples.

used to describe shale micropore specific pore volume and mesopore-macropore specific-pore volume, respectively. It is believed that the greater the specific surface, the greater the specific pore volume. By analyzing the specific surface-area data obtained in the whole rock sample gas adsorption tests of shale from the Chang 7 and Chang 9 of the Yanchang Formation, it was found that compared to micropores, the pore volume of mesopore-macropores are greater (shown in Fig. 3.59), except in one shale sample (sample 9, well Luping 36, 1382.31 m), which is abnormal. It is believed that mesopore-macropores constitute main fraction of the shale-pore volume. The presence of the abnormal sample may be related to the shale with extremely high TOC (25.9%) from well Luping 36. The shale micropore specific surface distribution is 0.6–4.7 m2/g, with an average of 1.63 m2/g, whereas the shale mesopore-macropore specific surface distribution is 2.0–5.9 m2/g, with an average of 3.8 m2/g. Therefore, it can be concluded that the specific surface area of 2–300 nm mesopore-macropores is twice the specific

FIGURE 3.59 Graph comparing whole rock sample nitrogen adsorption specific surface (mesoporemacropore) and carbon dioxide adsorption specific surface (micropore).

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.60 Bar chart comparing porosity percentage distribution in separated samples of sandy laminae (number 1, 3, 5) and shale laminae (number 2, 4, 6).

surface area of micropores, and accordingly the mesopore-macropore volume developed in shale is also greater than the pore volume of micropores. To compare the pore-volume distribution characteristics of different porediameter ranges more intuitively, the carbon dioxide adsorption specific-pore volume, nitrogen adsorption specific-pore volume, and the specific pore volume obtained through the mercury-intrusion method from three groups of separated shale samples are selected for direct comparison. As shown in Fig. 3.60, the nitrogen adsorption specific-pore volume of 2–100 nm pores is the highest among the six samples, followed by the specific-pore volume of micropores of finer than 2 nm, whereas the specific pore volume from the mercury-intrusion method of 100 nm–10 µm pores is the lowest. However, considering that the test principles and the analytical models of the gas adsorption methods and the mercury intrusion method are different, the absolute value of the parameters obtained are not directly comparable, and therefore only the specific pore volumes obtained with the gas adsorption methods are selected for comparison. The micropore (<2 nm) specific–pore volume distribution of the six samples is 0.08–0.12 cm3/g, with an average of 0.10 cm3/g. The mesopore-macropore (2–100 nm) specific pore volume is 0.23–0.86 cm3/g, with an average of 0.45 cm3/g. Thus, it was determined by directly comparing the gas adsorption specific pore volumes, that the mesopore-macropore specific pore volume is around 4.5 times that of the micropores. If considering the pore volume contributed by macropores coarser than 100 nm, this proportion will be even higher, and the development advantage of mesopore-macropore (greater than 2 nm) will be more pronounced. Based on the separated rock sample skeleton parameters obtained from the helium true density test, the theoretical porosity of the rock samples in a different pore diameter range can be further inferred, and comparison can be made (shown in Fig. 3.61). The porosity of every sample can be calculated by adopting the specific pore volume obtained from three physical property tests, using the following formula: [porosity (%) = specific pore volume (cm3/100 g)/

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FIGURE 3.61 Graphs of micro-meso-macro-pore diameter increment-accumulated distributions in separated samples of well YY7. (A) 1142.94 m, (B) 1155.19 m, (C) 1153.15 m.

(specific pore volume (cm3/100 g) + 100 g/skeleton density (g/cm3)) × 100 %]. It can be determined from the analysis that the porosity of micropores finer than 2 nm is 0.2%–0.31%, with an average of 0.26%, whereas the porosity of pores within 2 nm–10 µm is 0.6%–2.16%, with an average of 1.16%. Therefore, according to the inferred theoretical porosity, the mesopore-macropore porosity is around 4.5 times that of the micropore porosity. It is notable that the results are affected by various factors, such as the test principle and method, samplepreparation conditions, rock porosity indirectly obtained using this method, and that the cores tested using helium are not comparable, which are only relatively significant. Using the preceding comparison of shale specific-surface area, specific pore volume, and theoretically calculated micropore and mesopore-macropore porosity parameters, it can be identified that 2 nm–10 µm mesopore-macropores constitute a favorable percentage of the total shale-pore volume. The influencing factors on mesopore-macropore volume will be discussed using the pore volume distribution characteristics of the separated rock samples in different pore diameter ranges.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.62 Crossplot showing correlation between the shale micropore specific surface and the organic carbon content, maximum pyrolysis temperature of the Yanchang Formation.

Shale-pore-volume distribution characteristics are expressed by pore-diameter increment distribution and integral distribution characteristics, of which porediameter increment distributions can be used to describe pore-volume quantitative distribution of different pore diameters—that is, calculated absolute pore volume between two continuous pore diameters, plot the midpoint for current pore-diameter increment calculation. The integral distribution is also known as the accumulated distribution—that is, by accumulating the volume of different pores in an ascending order or a descending order, the volume of macropores, micropores, and their respective percentage to the total volume can be obtained. Comparison of the specific pore volume of micropores, mesopores, and macropores within the 0.3 nm–10 µm pore-diameter size range in the three groups of sandy laminae and shale laminae separated samples is shown in Fig. 3.62. It is apparent that the mesopore-macropore volume of the silty laminae in the same shale is clearly higher than that of the shale laminae, which is most pronounced within the 2–100 nm pore diameter size range in the nitrogen adsorption test. The nitrogen adsorption specific pore volume of the sandy laminae is 0.32– 0.86 cm3/100 g, with an average of 0.57 cm3/100  g, whereas the nitrogen adsorption specific-pore volume of the shale laminae is 0.23–0.39 cm3/100 g, with an average of 0.32 cm3/100 g. It can be seen that the pore volume within 2–100 nm of the sandy laminae is higher than that of the shale laminae, the difference distribution between them is 0.1–0.52 cm3/100 g, with an average of 0.26 cm3/100 g, and with the increase in pore diameters, the difference in the mesopore-macropore specific-pore volume between the sandy laminae and shale laminae is greater. The macropore-specific volume difference between the two kinds of lithologies measured in the mercury intrusion test is not clear. This is mainly limited by the test method and conditions, and the test data should not be compared with that of the gas adsorption method directly. According to the results currently obtained, the specific pore volume of the sandy laminae in the macropore range of 100 nm–10 µm is generally 0.01 cm3/100 g greater than the shale laminae. However, in the micropore range, the specific pore volume of the shale

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Lacustrine Shale Gas laminae is 0.02–0.03 cm3/100 g greater than that of the sandy laminae of the same shale. By comparing the accumulated distribution curves of the specific pore volume of both lithologies, it is clear that the percentage of micropore to the total pore volume of the shale laminae in each group of separated samples is higher than that of the sandy laminae. The micropore volume accumulated in the shale laminae accounts for 18.9%–33.0% of the total pore volume, with an average of 25.6%, while the percentage of micropore volume in the sandy laminae accounts for 9.4%–25.7% of the total pore volume, with an average of 15.7%. As the contribution of the micropore volume to the total pore volume is much less than mesopore-macropores, the total pore volume of sandy laminae is therefore still more than that of the shale laminae. Integrating the specificpore-volume analysis results from the three tests, the total specific-pore-volume difference of the sandy laminae and shale laminae is distributed between 0.04 and 0.17 cm3/100 g. The total specific pore volume of the sandy laminae is 0.08 cm3/100 g higher than that of the shale laminae. When calculating the rock sample skeleton density and comparing porosity (Fig. 3.61), it was found that the theoretical porosity of the sandy laminae is between 1.19% and 2.39%, with an average of 1.74%, whereas the porosity of the shale laminae is between 0.90% and 1.24%, with the average of 1.11%. It can be seen that the total porosity of the sandy laminae obtained through calculation is 0.3%–1.21% higher than that of shale laminae, which is 0.64% higher on average. The total porosity of the sandy laminae is around 1.56 times that of the shale laminae. As mesopore-macropores are the main contributors to porosity, the porosity of mesopore-macropores in the sandy laminae is mainly in the range of 0.89%–2.16%, with an average of 1.50%, whereas the porosity of mesopore-macropores in the shale laminae is in the range of 0.6%–1.01%, with an average of 0.83%. Thus, the porosity of mesopore-macropores in the sandy laminae is around 1.81 times that in the shale laminae. To summarize, compared with the nominally pure shale layer, mesopore-macropores (i.e., 2 nm–10 µm) are more developed in sandy laminae, and the more developed the sandy laminae, the greater the pore volume of the mesopore-macropores, and the more the total pore volume in the shale. Therefore, the sandy content is the main factor affecting the mesopore-macropore volume of shale. Among the influencing factors of micropore volume in shale, the impact of the sandy content is not high. It can be determined using the results of carbon dioxide adsorption test on the shale separated samples that in terms of micropore volume, the sandy laminae exhibit negligible difference compared to a nominally pure shale layer. The micropore specific pore volume of the shale laminae is 0.10–0.12 cm3/100 g, with an average of 0.11 cm3/100 g, whereas its micropore specific surface average is 3.12 m2/g. The micropore specific pore volume of the sandy laminae is 0.08–0.12 cm3/100 g, with an average of 0.10 cm3/100 g, whereas the micropore specific surface average is 2.78 m2/g. Thus, the volumes of micropores in some different lithologies are basically comparable, such that the micropore volume and surface area of sandy laminae are only slightly lower than the shale laminae.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.63 Crossplot showing the lack of correlation between the shale micropore specific surface and clay mineral contents of the Yanchang Formation.

The factors affecting micropore volume can be further assessed in terms of the carbon dioxide adsorption test results of whole shale samples from the Chang 7 and Chang 9 in the southern area of the Ordos Basin. At present, there is a lower limit of observation using SEMs, due to their spatial resolution, such that micropores (<2 nm) are not observable using an SEM. The pore type developed in this pore diameter range can only be inferred through the correlation between micropore physical property parameters and organic component parameters obtained using shale pyrolysis experiments. Micropore specific surface correlation analysis was carried out according to organic component contents and organic component parameters. It was found that the correlation among the micropore specific surface, TOC, and the maximum pyrolysis temperature Tmax (Fig. 3.62) indicate that micropores are mainly developed in organic matter, and the higher the extent of thermal evolution, the more developed the micropores. In terms of inorganic components, using micropore analysis of clay-rich rock and soil, previous workers have found that clay minerals, such as illite, smectite, and so forth have developed micropores that are mostly around 2 nm (Aringhieri, 2004). However, a positive correlation between micropore specific surface and shale clay mineral content is not apparent, and is poorer than for organic matter (Fig. 3.63). To summarize, shale mesopore-macropore volume is mainly controlled by the sand content in shale,that is, the development of sandy laminae, whereas micropore volume is mainly controlled by organic carbon content and organic matter maturity. However, the contribution of micropores to the total pore volume of shale is much lower than that of mesopore-macropore. Therefore, the higher sand content in shale and the more developed the sandy laminae, the higher the mesopore-macropore volume, and correspondingly, the higher the total pore volume of shale.

3.5  Characteristics of Pore Permeability Pores are an important reservoir space for shale gas storage, as well as a main parameter to determine the amounts of free gas and evaluate shale permeability. Shale-reservoir properties are mainly affected by factors, such as porosity, permeability, reservoir thickness, cracks, and brittle mineral contents in the rock.

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164

Lacustrine Shale Gas 3.6  Shale-Gas-Reservoir Properties In conventional reservoirs, porosity is a very important parameter used to describe reservoir characteristics. Shale-gas reservoirs are no exception, but compared with conventional reservoirs, the shale-gas-reservoir properties are poorer. The effective porosity of shale reservoirs is generally less than 10%, and their permeability is less than 1 mD, which corresponds to a typical reservoir with low porosity and permeability. According to a large number of analysis and test results using core analysis, the total porosity of the main shale-gas reservoirs in the USA are in the range of 2.0%–14.00%, with an average of 4.22%–6.51%. The well-logging porosity is in the range of 4.0%–12.00%, with an average of 5.2%. The permeability is generally less than 0.1 mD, with the average pore throat radius of less than 0.005 mm (Bowker, 2007). The core analysis data from the Barnett Shale gas zone in the USA indicates that the porosity of the development formation is less than 6%, and its permeability is less than 0.01 mD. Analysis of properties of shale core from the Chang 7 member of the Yanchang Formation conducted by laboratory tests indicates that its porosity varies over the large range of 0.5%–3.5%, with an average porosity of 1.82%. This can be broken down by porosity class, of which those with porosity in the range of 1.0%–1.5%, 1.6%–2.0%, and 2.1%–2.5% account for 33.33, 24.24, and 21.21% of total samples, respectively. Furthermore, those with porosity greater than 2.6% account for only 12% of total samples. The permeability of 70% of the samples is less than 0.01 mD, whereas samples with permeability in the range of 0.01–0.05 mD account for 21.21% of the total, and samples with permeability greater than 0.05 mD account for 9% of the total, giving an average permeability of 0.163 mD. The laboratory analysis of samples from the Chang 9 of the Yanchang Formation shows that the porosity varies in the range of 1.1%– 3.4% (as shown in Fig. 3.64). The permeability varies markedly in the range of 0.02–0.0034 mD, and there is no clear relationship between shale porosity and permeability (as shown in Fig. 3.65). Moreover, the shale mercury intrusion test curve is characterized by high displacement pressure. Generally, when the

FIGURE 3.64 Bar chart of shale permeability, porosity distribution in the Chang 7 member of the Yanchang Formation. (A) Bar chart of shale porosity distribution shows that the porosities of the main shale samples are distributed in the range of 1%–2.5%. (B) Bar chart of shale permeability distribution shows that permeability values of 70% of the shale samples are less than 0.01.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.65 Crossplot showing relationship between the porosity and permeability in the Chang 7 member of the Yanchang Formation.

FIGURE 3.66 Shale-mercury-intrusion curve in the Chang 7 member of the Yanchang Formation .

displacement pressure is more than 8.5 Mpa (as shown in Fig. 3.66), the pore throats are very fine with average diameters in the range of 0.01–0.04 µm, with the pore throat diameters largely finer than 0.1 µm.

3.7  Factors Influencing Shale Reservoir Properties 3.7.1  SEDIMENTARY ENVIRONMENT Based on the current understanding of shale sedimentary environments, the hydrodynamic environment in which clay minerals in shale are deposited can be mainly classified into two categories (as shown in Fig. 3.67). In standing water conditions, suspended sediment is deposited as fine silt- and clay-sized clay aggregates, known as loose ring floc. After being compacted, pores in the ring floc are often reduced to pores of nanometer scale in the major axis. In contrast, in strong hydrodynamic conditions, clay particles can wrap around each other and roll to form a nearly solid crumb floc, which can retain an equant pore state after being compacted. The pore aperture can reach a maximum on the micrometer scale. Clay floc formed under various hydrodynamic conditions

165

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Lacustrine Shale Gas

FIGURE 3.67 Schematic diagrams of the impact of sedimentation and compaction on pore structure of different mineral components of shale. (A) Clay floc deposited in standing water. (B) Clay floc deposited under water flow. (C) Silt-sized detrital particles of quartz, feldspar, and so forth.

exhibit different compression performances arising from their own structure and aggregate arrangement. Thus, the impact of sedimentation on the original sedimentary structure of clay minerals affects its pore evolution characteristics in the later diagenetic compaction process, and determines large variation in the range of porosity of pure shale, whereby the measured value can be in the range of 1%–4%. Sandy laminae developed in shale (as shown in Fig. 3.67C) can consist of mainly sand- or silt-sized feldspar and quartz detrital particles that are much harder than clay floc, and their shape tends to be more equant and have better capacity of preserving pores during the pore structure evolution process. In addition, their pore size is greater compared with pure shale, and their porosity is much higher. The results of studies by Ohmyoung et al. on the compression performance of different pores have also confirmed the conclusion that pores developed in rigid detrital particles have better preservation conditions and recovery capacities than those developed in clay minerals. Therefore, the early sedimentary environment and the late diagenesis of shale determine the shale composition and pore structure, thus affecting the extent of shale pore development, that is, affecting the size of shale porosity.

3.7.2 DIAGENESIS The process of diagenesis is also an important factor affecting shale porosity. The permeability of shale developed with sandy laminae is higher, especially the permeability of shale parallel to the bedding is an order of magnitude higher than that of pure shale (as shown in Table 3.2). When compared with the pure shale laminae in shale, the chemical diagenesis occurring in sandy laminae under medium pore fluid is also more intense, mainly reflected by strong and ubiquitous corrosion, as observed under the microscope. The high feldspar content contained in sandy laminae provides the basis for most of the occurrence of corrosion. As such, intragranular and intergranular corrosion pits and fissures are visible everywhere in potassium feldspar and albite, some can even form macropores to ultramacropores of tens of microns, which can be preserved

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 Table 3.2   Physical Properties of Shale Samples From the Yanchang Formation Tested With the Impulse-Attenuation Method

Well No.

Position Rock

Measured Permeability Porosity (%) (mD) Core Type

H36

Chang 7 Pure shale

1.69

0.000076

Perpendicular to the bedding

L93

Chang 9 Pure shale

2.22

0.000058

Perpendicular to the bedding

H36

Chang 7 Pure shale

3.54

0.000091

Perpendicular to the bedding

H36

Chang 7 Shale with 3.36 sandy laminae

0.000936

Parallel to the bedding

C100 Chang 7 Shale with 3.74 sandy laminae

0.000133

Perpendicular to the bedding

H36

Chang 7 Shale with 3.96 sandy laminae

0.000603

Parallel to the bedding

H36

Chang 7 Shale with 5.48 sandy laminae

0.000255

Perpendicular to the bedding

X54

Chang 7 Interbedded sand

7.09

0.000923

Perpendicular to the bedding

X54

Chang 7 Interbedded sand

7.14

0.003583

Parallel to the bedding

intact. Even stable siliceous cement in voids between detrital particles may also be corroded on their edges. Kaolinite, the most common secondary mineral after feldspar, is decomposed under acid conditions, although illite will precipitate when feldspar is decomposed, if the formation has K-rich fluid. Whichever the case, siliceous cement will be precipitated, causing abundant quartz crystals to form in voids between the detrital particles in sandy laminae, as observed under the microscope. As the sandy laminae contained in shale are proximate to shale laminae that are generating hydrocarbons, it is expected that the discharge of organic acids prior to substantial hydrocarbon generation in the shale laminae provides a strong acidic environment for the sandy laminae. The specific feldspar corrosion reaction process is as follows: 2KAlSi3O8 (Potassium feldspar) + 2H+ + H2O = Al2Si2O5 (OH)4 (Kaolinite) + 4SiO2 (silica) + 2K+ 2NaAlSi3O8 (Albite) + 2H+ + H2O = Al2Si2O5 (OH)4 (Kaolinite) + 4SiO2 (silica) + 2Na+

167

168

Lacustrine Shale Gas 3KAlSi3O8 (Potassium feldspar) + 2H+ + H2O = KAl3Si3O10 (OH)2 (Illite) + 6SiO2 (silica) + 2K+ + H2O 3NaAlSi3O8 (Albite) + K+ +2H+ + H2O = KAl3Si3O10 (OH)2 (Illite) + 3Na+ + 6SiO2 (silica) + H2O Thus, strong corrosion occurs in the sandy laminae developed in shale of the Chang 7 and Chang 9 members of the Yanchang Formation, which provides a large amount of pore space, increasing shale porosity.

3.7.3  HYDROCARBON INFILTRATION As discussed earlier, the extent of development of pores in sandy laminae in shale is high, resulting in high porosity. Because its porosity and permeability are higher than those of shale laminae, sandy laminae also receive hydrocarbon infiltration from the pure shale laminae. The results of observations under the microscope show that a large amount of hydrocarbons remains in voids between detrital particles in the sandy laminae. Fig. 3.68A shows a fresh fracture in a sandy lamina in shale from the Yanchang Formation, and indicates the relative contents of different elements (e.g., C from organic matter, Si and Al from silicates, Au from sputter coat). The local mass percentage of carbon is high—up to 100%. Under high magnification using the SEM, it was found that detrital particle surfaces are wrapped with a layer of carbonaceous matter, with very high carbon content indicated in the EDS spectra, and with some crystalline mineral faces still remaining on the surface, indicating that some voids in, or between, detrital particles are full or partly full of liquid hydrocarbon. Fig. 3.68B–C show the two-dimensional, polished surface of an argon-ionpolished section of shale from the Yanchang Formation. Liquid hydrocarbon retained in pores can also be observed in the argon-ion-polished section of a sandy lamina in shale from Zhangjiatan (shown in Fig. 3.68B). The lamina contains micron-sized intergranular pores in the interstices between, and surrounded by,

FIGURE 3.68 Bitumen in sandy lamina in shale of the Yanchang Formation. (A) Detritus of sandy lamina in shale wrapped in bitumen, fresh fracture sample. (B) Bitumen retained in intergranular pores in sandy lamina in shale, argon ion polished section. (C) Bitumen retained in sandy lamina in shale, argon-ion-polished section.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 silt-sized detrital particles. The EDS is used to examine the carbon distribution in the section, and the mass percentage of carbon on quartz and feldspar particle surfaces within the left upper area of the diagonal line is around 15%. This indicates that detrital particle surfaces with carbon residuum constitute pore walls of intragranular pores in the actual three-dimensional pore space, and that the pores had been filled with liquid hydrocarbon, which has remained on the detrital particle surfaces. Because the average atomic number (Z), which is related to density, of bitumen is much lower than inorganic minerals, its secondary electron (SE) and backscattered electron (BSE) responses are low during electron microscope imaging, and its grayscale is thus intermediate between pore (black) and inorganic minerals (medium-light gray). Therefore, residual bitumen distribution is readily discernible on the surface (as shown in Fig. 3.68C), similar to an oil spot, and is also distributed within intragranular pores on silt-sized detrital particle surfaces, reflecting the irregular two-dimensional form of the pores. Therefore, liquid hydrocarbon discharged by organic matter during hydrocarbon generation in shale occupies a lot of the pore space in sandy laminae, and a lot of the bitumen is retained in the intergranular pores in sandy laminae in particular, thus significantly reducing shale porosity. The shale samples used in the helium gas porosity test are shown in Fig. 3.68, have not been washed with oil, and the measured porosity does not contain pore space occupied by residual hydrocarbon. Based on empirical parameters obtained in rock soluble hydrocarbon extraction tests of the Chang 7 and Chang 9, it is predicted that the fraction of porosity occupied by liquid hydrocarbon in shale ranges from 0.96% to 5.34%, with an average porosity of 2.2%. It can be concluded that oil saturation of the sandy laminae in shale has great impact on shale porosity. To summarize, the sedimentary environment, diagenesis and late oil generation of the shale have a great effect on shale porosity. Compared with nominally pure shale laminae, the pores in the sandy laminae of shale are much coarser and have higher compression strength, while corrosion may further expand pore volumes. Therefore, the extent of development of sandy laminae has a great effect on shale porosity, although oil infiltration of the sandy laminae will result in porosity reduction.

3.8  Heterogeneity Characteristics With shale gas in North America successfully entering commercial development, and shale-gas resources being exploited and used to a great extent, others are gradually realizing that dark shale with abundant organic matter can generate and store gases, and form a self-generating and self-storage natural gas reservoir. Organic pores, intergranular pores, and particle pores developed in shale can effectively store oil and gas, and, as such, shale gas has become a new field for current oil-gas exploitation. In recent years, some Chinese and overseas researchers are also beginning to take notice of silty laminae developed in shale, and consider that the silty laminae constitute migration pathways and reservoir space (Broadhead, 1982). Silty laminae are also conducive to fracture development in shale, and thus have some effect on shale gas production

169

170

Lacustrine Shale Gas

FIGURE 3.69 Sandy lamina developed in the shale of Jinsuoguan Town, Tongchuan city. (A) Sandy lamina developed in Chang 7 shale at the intersection of the Tangne River. (B) Sandy lamina developed in shale of the Chang 9 at the three-way intersection.

(Davies and Vessell, 2002). Based on the examination of numerous field outcrops and observations of core samples under the microscope, shale in the Chang 7 and Chang 9 members of the Yanchang Formation in the Ordos Basin have developed a large amount of silty laminae or interlayers, with ash gray silty interlayers, silty laminae, and dark, homogeneous shale stacked in multiple layers, and with relatively well-developed low-angle cross-bedding, parallel bedding, bottom-scouring structures, and water-escape structures in shale. The homogeneity in the sandy laminae of shale is poor, and the extent of lateral continuity differs greatly, with some soft particles in the sandy laminae, such as mica, as well as the actual bedding surfaces deforming due to compaction. Fig. 3.69A shows two thin silty laminae developed in dark black shale at the three-way intersection of Zhangjiatan near Tangne River, Jinsuoguan Town, and Tongchua City, whereas Fig. 3.69B shows the silty interlayers developed in the shale of the Chang 9 at the three-way intersection of Jinsuoguan Town, Tongchua City. Therefore, it can be concluded that silty laminae and interlayers are quite well developed in these shales. Based on the results of analysis of drilling, sandy laminae are quite developed in the shale of the Chang 7 of the Yanchang Formation in the Ordos Basin. Although the extent of development in the shale at Lijiapan is relatively poor, the sandy laminae can be classified into two categories according to differences in their morphological characteristics and degree of lateral continuity: (1) straight type; and (2) corrugated type. The boundary plane of straight sandy laminae is straight and regular, exhibits small change laterally with respect to thickness, is distributed horizontally or nearly horizontally, and often occurs in groups. The corrugated laminae are of lenticular or continuous wave form, which exhibit poor lateral continuity and large changes in thickness, often pinching-out or combining with other laminae. Internally, the laminae have visible graded changes, which often also develop such sedimentary structures as low-angle bedding and bottom-scouring surface.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.70 Rock type chart showing shale core samples from the Chang 7 and Chang 9 of the Yanchang Formation in the south of the Ordos Basin (left), schematic drawings (center), and type specimens (right).

Shale can be classified according to the development characteristics of sandy laminae in mudstone (Aplin and Macquaker, 2011), as shown in Fig. 3.70. The sequence from top to bottom, that is, with increasing burial depth, is: (1) massive mudstone, (2) horizontal mudstone laminae, (3) lenticular laminae to modified laminae mudstone, (4) small slump mudstone laminae, (5) large slump mudstone laminae, (6) small bioturbated mudstone laminae, and (7) large bioturbated mudstone laminae. Fig. 3.70 shows a schematic diagram of rock. The yellow part in the diagram is shale of medium grain size, that is, sandy laminae, while on the right is a real shale example, and on the left is the corresponding core photo of the lithofacies developed in the shale of the Yanchang Formation in the south area of the Ordos Basin. The first two types mentioned in the preceding list comprise the bulk of the shales, with minor bioturbation, which are rarer in the targeted sections by a large scale. Based on the results of core observations, the shales at Zhangjiatan and Lijiapan are mainly equivalent to massive mudstone and horizontal mudstone laminae, in which silt of coarser grain size is mainly suspended and sedimented, whereas slump caused by late underflow transformation and drainage is common, and minor bioturbation is often visible locally. The sandy laminae in core samples from the Chang 7 and Chang 9 in Well YY1 are shown in Fig. 3.71, and the results of measurement of these laminae are shown in Fig. 3.72. Sandy laminae or interlayers developed in the core of the shale section at Zhangjiatan were measured, and reached up to 1880 layers with a cumulative thickness of 601.13 cm, whereas the sand content is around 11.89%. The frequency of occurrence of the sandy laminae is 37.2 layers per meter, and a single layer thickness of sandy laminae is mostly in the range of 0.2–2 mm, with the thickest reaching up to tens of cm. The extent of development of sandy

171

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Lacustrine Shale Gas

FIGURE 3.71 Photographs of polished sawn drill core showing sandy laminae in the Zhangjiatan Shale of the Yanchang Formation.

laminae in shale at Zhangjiatan is not uniform, and sandy laminae at 1357.78– 1380 m and at 1401.14–1416.71 m are quite well developed, with their sand contents of 11.52 and 22.4%, respectively, and frequency of occurrence of 67.8 and 36 layers per meter, respectively. The sandy laminae at 1380–1393.94 m and 1395.7–1401.14 m, in the middle of the same section are quite underdeveloped, and the definition of the boundaries of the sandy laminae is quite poor. Their sand contents are 3.19 and 2.64%, respectively, and their frequencies are 18.8 and 14.1 layers per meter, respectively. The measured length of the shale section at Lijiapan is 1150.42 cm, and the cumulative thickness of sandy laminae is around 114.55 cm, whereas the sand content is around 9.96%. The frequency of occurrence of the sandy laminae is 19.1 layers per meter, with the thickness of a single sandy lamina mostly in the range of 0.2–2 mm (as shown in Fig. 3.72).

FIGURE 3.72 Histograms of single layer thicknesses of sandy laminae in shales at Zhangjiatan (A) and Lijiapan (B) in Well YY1.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

173

SECTION 5  LACUSTRINE SHALE RESERVOIR EVALUATION Different from normal, conventional oil-gas reservoirs, shale-gas reservoirs belong to a type of self-generating and self-storage gas reservoirs. Conventional reservoir evaluation includes analysis of a set of characteristics, such as petrological, physical properties, and other basic characteristics. However, in addition to the preceding analyses for conventional reservoirs, shale-gas reservoir evaluation also involves thoroughly weighing both the positive and negative affect of various geological factors, including shale mineral composition, structure, clay, maturity, kerogen type, as well as maturity, burial depth, temperature, pressure, and so forth.

1  LACUSTRINE SHALE GAS RESERVOIR EVALUATION METHOD 1.1  Evaluation Parameters and Grading At present, no unified codes and standards are available for shale-gas-reservoir evaluation. Because shale gas is a natural gas accumulated in-situ at the source rock area, it belongs to source rock retained gas, which thus has self-generating and self-storage characteristics. Therefore, evaluation of shale-gas reservoirs must consider reservoir-gas generation capacity and storage capacity. A plan of evaluation could include the following: (1) select three reservoir evaluation parameters based on shale-gas geologic characteristics, influencing factors and actual testing method; (2) study the control of each parameter on shale reservoir; (3) classify parameter range in combination with the actual conditions of lacustrine shale gas; (4) compare with Chinese and overseas shale-gas evaluation-parameter ranges, and (5) establish a shale-gas-reservoir evaluation parameter grading table (Table 3.3).

Table 3.3   Evaluation Parameters for Grading Lacustrine Shale-Gas Reservoir Evaluation Parameter Value Parameter Level

Organic Carbon Maturity Content (%) (%)

Brittle Mineral (%)

Porosity Thickness Burial Depth (%) (m) (m)

Level 1

≥6.0

1.5–2.0

≥40

≥8

≥50

300–1500

100

Level 2

4.0–6.0

1.1–1.5 or 2.0–3.0

35–40

4–8

35–50

1500–2500 or <300

80

Level 3

2.0–4.0

3.0–4.5

30–35

2–4

25–35

2500–3500

60

Level 4

1.0–2.0

0.5–1.1 or >4.4

20–30

1–2

15–25

3500–5000

40

Level 5

0.5–1.0

<0.5

<20

<1

<15

>5000

20

Scoring Criteria

174

Lacustrine Shale Gas American shale-gas-reservoir evaluation mainly considers the following: (1) reservoir gas producing and storage capacity, (2) fracturing performance, and (3) economic efficiency. The gas-producing capacity includes organic-carbon content, maturity and thickness, whereas the gas-storage capacity includes effective thickness and porosity, the fracturing performance mainly refers to brittle mineral content, and the economic efficiency mainly refers to drilling and burial depth. Lacustrine shale gas reservoir evaluation is carried out using the following parameters: 1. Shale burial depth

2.

3.

4.

5. 6.

The depth of marine shale gas developed by petroleum industry in the USA is generally less than 3000 m. Shale-gas exploitation in China has just begun, and considering exploitation technologies and preservation conditions, the burial depth conducive for lacustrine shale gas formation and development is 1000–3000 m. Single-layer thickness of shale As the main source for shale-gas generation and accumulation, a certain thickness of gas-bearing shale constitutes the minimum basic condition to form shale gas. It is also an important factor affecting shale-gas resource abundance, because thicker shale with abundant organic matter ensures more shale-gas resource and fracturing conditions. Analysis of the geological conditions of shale-gas developments in North America shows that the single-layer thickness of shale conducive for lacustrine shale-gas formation and development is not less than 15 m. Organic-carbon content (TOC) The organic-carbon content of marine gas-bearing shale systems currently developed by large-scale commercial operations in the USA is 0.5%– 25.0%. In combination with the actual conditions of lacustrine shale gas in China, a shale-gas reservoir with the organic carbon content of 1.0% is considered an effective shale. Organic-matter maturity Shale gas produced in the USA is mainly derived from thermogenic gas, which accounts for more than 85% of all the shale gas. The maturity of most of the organic matter in these shales is Ro ≥ 1.1%. For lacustrine deposits of the Mesozoic erathem in the Ordos Basin, the average Ro value of oil shale in the Chang 7 of the Yanchang Formation is 0.72%, whereas that in the Chang 9 is 0.74%, and the kerogen type is mainly Type II. At the same time, different kerogen types have different requirements of Ro. Brittle mineral contents As brittle mineral contents affect shale brittleness and fracture development, it is very important to define the shale-gas layer for commercial exploitation. Shale reservoir physical properties

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3 Because shale-gas-reservoir physical properties directly affect shale-gas production capacity, it is also of vital importance for the accumulation of shale gas. Considering the degree of difficulty in obtaining the physical-property parameters that are essential measures for shale fracturing, we believe that it is reasonable to select porosity as the most representative of the physicalproperty parameters. Considering that the importance of each parameter to the specific evaluation area is different, it is necessary to carry out a weight analysis on every parameter, and to establish a weight coefficient table according to the impact of every evaluation parameter on shale-gas reservoir (Table 3.3), and then finally, carry out a comprehensive evaluation.

1.2  Reservoir Evaluation Procedure Shale geologic characteristics and shale-gas-reservoir development techniques are different, and as such the procedure for shale-gas-reservoir evaluation will also vary from area to area. Based on the experience gained in the shalegas-reservoir evaluation of the Yanchang Formation in the south of the Ordos Basin, the procedure for lacustrine shale-gas reservoirs is as follows: (1) classify the shale-gas reservoir into different evaluation units according to the lacustrine shale-gas-reservoir evaluation criteria and different strata; (2) input such parameters as burial depth, organic-carbon content, maturity, thickness, physical properties, brittle mineral content of every evaluation unit in order to establish a reservoir parameter database of different shale-gas-reservoir evaluation units; (3) refer to the lacustrine shale-gas-reservoir evaluation parameter grading in Table 3.4 to find out the range of each parameter, and then assign the corresponding evaluation score F (including burial depth FH, organic carbon FTOC, vitrinite reflectance FRo, thickness Fh, porosity FΦ, brittle mineral content FSi); (4) assign the weight coefficient P (PH, PTOC, PRo, PSi, PΦ, Ph) of the shalegas-reservoir evaluation parameters; and (5) combine the earlier determined evaluation score F of all evaluation parameters of the shale-gas reservoir and its weight coefficient P to calculate the comprehensive evaluation coefficient of the shale-gas reservoir F: F = PHFH + PTOCFTOC + PRoFRo + PSiFSi + PΦFΦ+PhFh Finally, rank the shale-gas-reservoir evaluation units of different strata according to the shale-gas-reservoir comprehensive evaluation coefficient F value calculated. Table 3.4   Lacustrine Shale-Gas Reservoir Evaluation Parameter Weight Coefficients

Organic Carbon Content

Maturity

Siliceous Content

Porosity

Burial Thickness Depth

0.25

0.15

0.15

0.10

0.20

0.15

175

176

Lacustrine Shale Gas 2  LACUSTRINE SHALE GAS RESERVOIR EVALUATION 2.1  Evaluation Unit Classification When classifying the reservoir evaluation unit of the lacustrine shale gas in the Ordos Basin, we mainly take into account the production-management convenience, shale thickness, and maturity distribution. The shales of the Chang 7 and 9 members of the Yanchang Formation of the Mesozoic Erathem in the Southern Ordos Basin have entered the maturity stage across the whole area. Therefore, the reservoir evaluation unit of the Yanchang Formation is classified mainly based on shale thickness in combination with maturity. The shale-gas reservoir of the Chang 7 of the Yanchang Formation is classified into eight evaluation units (as shown in Fig. 3.73), except that the unit boundary of the Ganquan-Fuxian area is a boundary with Ro greater than 1.1%, whereas the boundaries of the other units are based on thickness. The shalegas reservoir of the Chang 9 of the Yanchang Formation is classified into four evaluation units mainly based on the shale thickness distribution (as shown in Fig. 3.74).

FIGURE 3.73 Shale gas reservoir evaluation unit distribution of the Chang 7 of the Yanchang Formation.

Lacustrine Shale Gas Reservoir in the Ordos Basin  Chapter 3

FIGURE 3.74 Shale gas reservoir evaluation unit distribution of the Chang 9 of the Yanchang Formation.

In this way, the shale-gas reservoir of the Chang 7 of the Yanchang Formation is classified into the following eight evaluation units: (1) Zichang-Yanchang area; (2) Yan’an-Yanchang area; (3)Ya’an-Yichuan area; (4) Ganquan- Fuxian area; (5) Zhidan-Ansai area; (6) area to the south of Jingbian; (7) Northern DingbianWuqi area; and (8) Sourthern Dingbian-Wuqi area. The shale-gas reservoir of the Chang 9 of the Yanchang Formation is classified into the following four evaluation units: (1) Yang’an-Yichuan area, (2) Zhidan-Fuxian area, (3) Dingbian-Ansai area, and (4) Wuqi area.

2.2  Evaluation Process and Results Appropriate scores were given by inputting the organic-carbon content, maturity, thickness, burial depth, physical properties, and siliceous contents of each evaluation unit, and calculate the integrated score of every parameter (Table 3.5). It can be seen from the evaluation results that the shale-gas reservoir of the Chang 7 member of the Yanchang Formation in the GanquanFuxian area is of the highest quality, whereas that of the Chang 9 ­member of the Yanchang Formation in the Zhidan-Fuxian area is also of the highest quality.

177

Table 3.5   Summary Sheet of Lacustrine Shale-Gas-Reservoir Evaluation for the Ordos Basin TOC (%) FM

No. Area Name

Ro (%)

Value Score Value

Brittle Mineral (%) Porosity (%)

Thickness (m)

Burial Depth (m) Evaluation Score Value Score Value Score Value Score Value Score Coefficients

Chang 7 1

ZichangYanchang

1.3

40

0.6∼0.7 40

>0

100

4.6

80

22.5

40

200 ∼800

100

62

2

Yan’anYanchang

1.4

40

0.6 0.7

40

>0

100

2.0

60

37.5

80

200 ∼800

100

68

3

Yan’an-Yichuan 1.2

40

0.5∼0.8 40

>0

100

0.9

20

52.5

100

200∼900

100

68

4

GanquanFuxian

3.0

60

0.7∼1.2 60

>0

100

1.5

40

77.5

100

800∼1400

100

78

5

Zhidan

1.7

40

0.8∼1.1 40

>0

100

1.6

40

45.0

80

1000∼1800 80

63

6

Southern Jingbian

1.0

40

0.6∼0.8 40

>0

100

2.5

60

25.0

60

1000∼1800 80

61

7

Northern 1.7 Dingbian-Wuqi

40

0.7∼0.9 40

>0

100

1.7

40

32.5

60

1800∼2300 80

59

8

Sourthern 3.5 Dingbian-Wuqi

60

0.7∼1

40

>0

100

1.2

40

45.0

80

1800∼2300 80

68

Chang 9 1

Yan’an-Yichuan 3.9

60

0.7∼0.9 40

>0

100

1.6

40

27.5

60

400∼1100

100

67

2

Zhidan-Fuxian 2.5

60

0.7∼1.2 60

>0

100

3.4

60

47.5

80

1000∼1500 100

76

3

Dingbian-Ansai 2.5

60

0.6∼1

40

>0

100

1.9

40

26.4

60

1500∼2500 60

61

4

Wuqi

1∼1.1

40

>0

100

1.2

40

25.3

60

2000∼2500 60

46

—

Note: the evaluation parameter weight coefficients in the table can be referred to Table 3.4.