Comparative Studies of Three Nonfractured Unconventional

Article pubs.acs.org/EF

Comparative Studies of Three Nonfractured Unconventional Sandstone Reservoirs with Superlow Permeability: Examples of the Upper Triassic Yanchang Formation in the Ordos Basin, China Ruifei Wang,*,† Guangjian Xu,‡ Xuguang Wu,§ Zhongqun Liu,§ and Yungang Chi† †

College of Petroleum Engineering, Xi’an Shiyou University, Xi’an 710065, China Department of Geology and Geophysics, Texas A&M University, College Station, Texas 77843, United States § Sinopec North China Company, Zhengzhou 450006, China ‡

ABSTRACT: Unconventional sandstone reservoirs with ultralow permeability (1 mD < Kair < 10 mD, where Kair represents the permeability in air) and superlow permeability (0.1 mD < Kair < 1 mD) in China are widely distributed in major basins and have significant economic potential. (Here, D is a permeability unit: 1D = 1000mD = 1 μm2.) A comparative study has been performed here on three Upper Triassic sandstone reservoirs with superlow permeability in the southern Ordos Basin to understand the characteristics of each reservoir, the differences in reservoir porosity and permeability, and their causes. The study shows that pore type is the main factor that controls the physical property of nonfractured, superlow permeability sandstone reservoirs in the area of study. The main pore type observed in all three reservoirs is dissolution-enhanced intergranular, which comprises a maximum of 70% of the total porosity. Remnant intergranular and intragranular dissolution pores are also observed in these reservoirs. The pore throat size of dissolution-enhanced intergranular pores is generally 2−3 times larger than that of the intragranular dissolution type. Therefore, the reservoir with the greatest quantity of dissolution-enhanced intergranular pores has a poorer sorting of pore throat sizes and stronger microscopic heterogeneity. The dissolution-enchanced intergranular pores, on the other hand, also contribute to higher surface porosity, larger average pore diameter, higher pore throat coordination value, and, most importantly, higher permeability. This latter result contrasts with observations of conventional sandstone reservoirs, in which better pore throat sorting is favored for permeability.

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INTRODUCTION Unconventional sandstone reservoirs with superlow permeability (0.1 mD < Kair < 1 mD, where Kair represents the permeability in air) have been extensively developed in China as an important component of unconventional resources. They are widespread in many large-scale sedimentary basins, such as the Ordos Basin, the Sichuan Basin, the Bohai Bay Basin, the Songliao Basin, and Junggar Basin.1 With current technology, sandstone reservoirs with a permeability of 1 mD. Very few studies have focused on the properties of sandstone oil reservoirs that have superlow permeability.17−23 Spencer studied the relationship between porosity and permeability, as well as the stress sensitivity of a low-permeability reservoir in the western United States.17 That research showed a plausible © 2016 American Chemical Society

trend of decreasing permeability with decreasing porosity. Clarkson identified the flow unit and studied the pore structure of the Lower Triassic Montney formation tight gas reservoir in western Canada via N2 adsorption.22 Wang et al. studied the micropore structure in ultralow permeability sandstone reservoir (1 mD < Kair < 10 mD) and the feature parameters of microscopic pore throats in deeply buried low-permeability sandstone reservoirs.18−20 Guo et al. characterized tight sandstone reservoirs, in terms of pore size, pore throat types, and throat size in the Taibei Sag and its relationship with microfacies and diagenesis.24 Instead of focusing on a single unconventional sandstone reservoir, three sequential superlow permeable sandstone reservoirs from the same Yanchang Formation (Ordos Basin) provide a unique opportunity to compare reservoir characteristics and properties and link them to the evolution of the reservoirs. In this paper, we follow Li’s classification of unconventional sandstone reservoirs based on properties of tight oil and gas sandstone reservoirs in China.25 We classify low-permeability sandstone reservoirs into three categories, based on air permeability: • low-permeability (10 mD < Kair < 50 mD), • ultralow permeability (1 mD < Kair < 10 mD), and • superlow permeability (0.1 mD < Kair < 1 mD). Received: July 19, 2016 Revised: October 21, 2016 Published: November 30, 2016 107

DOI: 10.1021/acs.energyfuels.6b01616 Energy Fuels 2017, 31, 107−118

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Figure 1. Location map of the area of study in the Ordos Basin (modified from Yang et al.,30 Hanson et al., and Jiang et al.32).

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GEOLOGICAL SETTING The Ordos Basin, which is the second-largest basin in China, is located in central China (Figure 1). It has an area of 250 000 km2 and consists of six tectonic sections: the Yimeng Uplift, the Jinxi flexure belt, the Yishan Ramp, the Tianhuang Depression, the Western edge over the thrust belt, and the Weibei Uplift. The Ordos Basin is a stable sedimentary basin that was formed on the North China Craton.26−29 The Chang 6 Sedimentary microfacies floor plan in Weibei oil field presents the palaeogeographical map to show the palaeogeographical conditions (Figure 2). The study area is located in the Weibei uplift, in the southern Ordos Basin (Figure 1). It is a N−S trending monocline dipping west at 1°−2°. The Upper Triassic Yanchang Formation is the primary hydrocarbon producing formation in the study area; it is ∼3280 ft thick (1000 m) in which sandstone reservoirs with superlow permeability are present (Figure 3). The Yanchang Formation was deposited in a lakedelta system, which is characterized by a wide distribution of grain sizes, low textural maturity, large quantities of feldspar and lithics, and high content of carbonates and clay minerals. The Chang 3, Chang 6, and Chang 7 Members (hereafter

referred to as C3, C6, and C7, respectively) from the Yanchang Formation comprise the sandstone reservoirs in this region. The C3 and C6 members were deposited in a shallow braided delta front, whereas the C7 member was a deep-water gravity flow deposit, as a result of the delta front slump. The main source rock of the Yanchang Formation is a thick, widely distributed shale unit called Zhangjiatan Shale at the bottom of the Chang 7 ,ember. It is a mature, high-quality source rock. The total oil in place of the reservoirs in the area of study is 1 billion barrels.

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METHODS

The research summarized in this paper mainly involves core observation from 52 wells, petrographic thin-section study, scanning electron microscopy (SEM), mercury injection capillary pressure (MICP) measurements, whole rock X-ray diffraction (XRD) analyses, and XRD clay mineral measurements. There are 127 casting thin sections and 194 regular thin sections available for us to study the rock constituents (e.g., lithic fragment, cement, pores), grain sorting, cement type, pore and pore throat type, and connection between pore and pore throat. The surface porosity (percentage of area of pores over total area of a sample of a thin section) was estimated using point counting. 108


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Figure 2. Chang 6 Sedimentary microfacies floor plan in Weibei oil field. Reservoir physical property analysis was conducted on 1232 samples with a diameter of 25.4 mm. Sample porosity was determined using a helium porosimeter (Model KXD-III) with an accuracy of 1% and an error of ±0.3%. The permeability of samples was measured using a gas permeation analyzer. With correction, sample gas permeability can be obtained with an accuracy of 0.1 mD, with an error of ±0.003 mD. Grain size distribution analysis of 44 reservoir rock samples was performed on a sonic vibrating sieve particle size analyzer (Model SFY-B2000). The reservoir rock grain size, the percentage content of different grain sizes, the sorting coefficient, and the kurtosis were obtained. A detailed examination of lithic minerals, authigenic minerals, pore throat type, and pore distribution within the reservoir rock samples was performed using a scanning electron microscopy (SEM) system (JEOL, Model JSM-5500LV) that was equipped with an energydispersive spectroscopy (EDS) detector (Model QUANTAX400). Semiquantitative clay mineral composition and whole rock composition analyses were conducted on 28 and 21 samples, respectively, using a high-resolution D8 Discover X-ray diffraction system. In order to study pore throat size distribution and the contribution of different pore throat sizes to reservoir permeability, a Micromeritics Auto Pore IV 9520 High Pressure Mercury Injection Apparatus was used to measure 71 samples. Parameters such as mercury saturation at various mercury injection capillary pressures, efficiency of mercury

ejection, pore throat diameter, sorting coefficient of pore throat, etc. are determined.

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RESULTS Petrology Features. Lithic Composition. The composition of reservoir rocks was obtained through point counting from 321 thin sections. The C3, C6, and C7 members are mainly lithic arkose sandstones and feldspathic litharenite sandstones (Figure 4). The detrital compositions of the sandstones in each reservoir are approximately the same (∼98.5%). Compared to the C6 and C7 members, the C3 sandstone has the highest quartz content, quartz-to-feldspar ratio, and quartz-to-othercomponents (feldspar plus lithics) ratio. It indicates that the C3 member has the highest degree of mineralogical maturity in the three reservoirs, which reflects a decrease in mineralogical maturity with depth (see Table 1). The lithic components of the sandstone reservoir increase from C3 (19.31%) to C6 (24.04%) to C7 (26.40%). Within the lithic fragments, the metamorphic and volcanic fragments in all three reservoirs are approximately the same, with regard to area percentage. The discrepancy in lithic content in reservoir rocks is attributed to the sedimentary lithic fragments, which are 4.35%, 9.38%, and 12.84% in the C3, C6, and C7, respectively. The variations within sedimentary lithics of these three 109


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quartz and feldspar. The mica in the C3 reservoir often forms layers parallel to bedding planes or bends around grains. Grain Size Distribution. Grain size distributions of reservoir samples (Table 2) show that the reservoir sandstones are composed of 60%−70% fine-grained sand, 21%−37% veryfine-grained sand, and small percentages of medium sand and coarse silt. The average grain size of the sandstones decreases from C3 to C7 to C6. In the study area, the Chang 10 (C10) member was deposited at the formation of a lacustrine basin. The C7 member was formed during rifting of the basin. The C6 members were deposited during tectonic inversion of the basin. The depressional lacustrine basin began to wither away when the C3 member was deposited. Compared to the C6 and C7 members, the C3 member was deposited in a shallower water environment, thus, leading to coarser grain sizes. Cement. Carbonate minerals are the dominant cements observed in the reservoir rocks, varying from 7.41% to 8.93% (see Table 1, as well as Figure 5). Calcite cement is mostly present in anhedral shapes, fills in intergranular pores, and sometimes replaces the edge of detrital grains. The intragranular pores of the reservoir rock are often filled with dolomite cement, which is sometimes coated with illitic clay. Other cements present in the reservoir rocks from highest to lowest content are clay minerals, iron oxide, and silica cements. Mechanical compaction during early diagenesis of reservoir rocks leads to a reduction in a large quantity of pores. Pressure solution processes associated with compaction cause the overgrowth of quartz and feldspar and cementation of silica cements. In addition, carbonate and clay cements formed during cementation also decrease reservoir space, reducing reservoir porosity and permeability. During compaction and cementation, the texture of grains in the rock becomes more compacted, forming line, concave−convex intergranular contacts, and preferred orientation of detrital grains. From C3 to C6 to C7, the degree of mechanical compaction and cementation increases and the degree of pore development decreases. Clay Cement. The X-ray diffraction (XRD) analyses of 28 samples (Table 3) show that clay minerals are rarely found in the matrix of the reservoir samples. Clay minerals are products of the dissolution of detrital feldspar grains and rock fragments. Dissolution of detrital grains between grains or within grains occurs to form dissolution-enhanced intergranular and intragranular pores. This process enhanced reservoir porosity and permeability. In contrast, abundant clay minerals such as filamentous illite, booklike kaolinite, and chlorite flakes fill the pores between grains (see Figures 5e and 5f), which reduces the reservoir porosity and permeability. The overall clay mineral contents increase from C3 (15.51%) to C6 (16.61%) to C7 (20.20%). As the depth of burial increases (from C3 to C6 to C7), the illite/smectite (I/S) clay content increases from 3.34% to 9.83% and the illitic clay content increases from 3.26% to 6.03%. However, the percentage of smectite layers (%S) in I/S decreases from 16.25% to 15%. The C3 sandstone contains a kaolinite content of 4.67%, whereas kaolinite is rare in C6 and C7 sandstone (contents of ≤0.2%). Changes in the chlorite content in the reservoir rocks are very small (see Table 3). The variations of clay mineral content from C3 to C7 are in accordance with increased digenesis with deeper burial, at which point smectite clays turn into illitic clay.35,36 Because of the absence of mixed-layer chlorite/smectite (C/S) in the clay

Figure 3. Stratigraphic column of the Yanchang Formation and its members in the Ordos Basin. The Chang 1 Member within the Yanchang Formation is eroded in the area of study. Data are obtained from stratigraphic correlation of 78 wells in the area of study.

Figure 4. Ternary diagram of the composition of the C3, C6, and C7 reservoir sandstones. [Legend: Q, quartz; F, feldspar; L, debris; I, quartzarenite; II, subarkose; III, sublitharenite; IV, arkose; V, lithic arkose; VI, feldspathic litharenite; VII, litharenite; total number of samples (n), 321 (C3, 185; C6, 63; C7, 73).]

reservoir rocks might be related to multiple sediment provenances in the basin.33,34 The mica content in the C3 reservoir is the highest, which agrees with the highest quartz plus feldspar content (79.63%) in the C3 member, since mica often coexists with fine-grained 110


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Table 1. Composition of the (a) Detrital Components and (b) Cement in the C3, C6, and C7 Sandstones from Thin-Section Petrography (a) Composition of Detrital Grains (%) lithics member

total number of samples

quartz

feldspar

fragment

C3 C6 C7

185 63 73

55.54 50.13 49.75

24.09 25.79 22.94

19.31 24.04 26.40

volcanic

metamorphic

2.16 12.8 2.61 12.05 2.22 11.34 (b) Composition of Cement (%)

sedimentary

mica

4.35 9.38 12.84

6.14 5.35 5.38

member


iron oxide

silicate

carbonate

clay

kaolinite

chlorite

C3 C6 C7

185 63 73

1.60 1.80 2.48

1.92 1.04 1.01

8.28 7.41 8.93

3.80 4.24 2.39

7.33 0.6 0.73

5.18 3.09 4.3

Table 2. Grain Size Distribution of the C3, C6, and C7 Sandstones Distribution (%) member


medium sand (1 < Φ < 2)

fine sand (2 < Φ < 3)

very fine sand (3 < Φ < 4)

coarse silty sand (4 < Φ < 5)

fine silty sand (5 < Φ < 8)

C3 C6 C7

27 7 10

5.81 2.38 4.37

71.49 59.04 63.30

20.93 36.96 32.24

2.75 1.63 1.39

0.86

Figure 5. (a) A sandstone sample from the C3 member under plane polarized light. Intergranular pores (Pinter), intergranular dissolution pores (DPinter), and small amounts of intragranular dissolution pores (DPintra) are observed. Mica is deformed due to compaction and shows a preferred orientation. (b) A cast thin section from C6 reservoir showing intergranular pores, as well as intergranular and intragranular dissolution pores in rocks. The red space indicates pores. (c) A cast thin section from C7 sandstones showing intergranular and intragranular dissolution pores in rocks. The red space indicates pores. (d) Scanning electron microscopy (SEM) image of C3 sandstone; secondary quartz, feldspar, and bookshelf stacks of kaolinite (K) fill in the intergranular pores. (e) SEM image of a C6 sandstone sample showing dolomite (Dol), illite (I), and mica (M). (f) SEM image of C7 sandstone samples showing intergranular pores that are filled with secondary quartz (Q), albite crystals (A), chlorite flakes (C), and some hairlike illite (I).

that the pH value in the formation fluid increases from C3 to C7. The lack of ferrous iron in the formation fluid inhibits the transition from smectite to chlorite and from kaolinite to

minerals and the potassium-rich formation water, the transition from kaolinite to chlorite and from smectite to chlorite is rare or has not occurred. Analysis of the formation water suggests 111


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Energy & Fuels Table 3. Composition of Clay Minerals in the C3, C6, and C7 Members from XRD Analysis of 28 Samples member

a

sample

clay (%)

illite/smectite (%)

illite (%)

kaolinite (%)

chlorite (%)

S%a

C3 C3 C3 C3 C3 C3 C3 C3 C3 C3 C3

WB7-9 WB7-19 WB7-33 WB7-48 WB11-8 WB11-18 WB11-31 WB15-9 WB15-21 WB15-39 WB15-57 C3 average

18.00 15.30 17.30 19.60 18.50 20.70 26.00 9.20 12.10 6.30 7.60 15.51

5.40 2.91 2.25 2.74 6.48 3.52 7.02 3.68 1.21 0.76 0.76 3.34

6.30 7.65 4.50 2.94 2.59 3.52 3.90 2.39 0.97 0.38 0.76 3.26

0.00 0.00 0.00 0.00 9.44 13.66 12.48 1.66 6.29 3.47 4.33 4.67

6.30 4.74 10.55 13.92 0.00 0.00 2.60 1.47 3.63 1.70 1.75 4.24

20 20 20 20

C6 C6 C6 C6 C6 C6 C6 C6 C6 C6 C6 C6

WB7-53 WB7-61 WB7-73 WB7-80 WB7-96 WB11-41 WB11-49 WB11-61 WB15-68 WB15-90 WB15-119 WB15-146 C6 average

21.10 14.70 20.00 25.20 21.40 19.40 20.90 18.40 10.40 10.90 7.30 9.60 16.61

10.34 8.53 11.00 12.35 13.05 12.03 11.08 9.94 4.16 2.94 1.90 4.42 8.48

7.60 3.68 5.80 8.32 6.21 4.85 7.11 4.78 3.12 1.85 1.02 3.74 4.84

0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.00 0.52 1.09 0.58 0.19 0.2

3.17 2.50 3.20 4.54 2.14 2.52 2.72 3.68 2.60 5.01 3.80 1.25 3.09

15 30 30 25 30

20 10 15 20 16.00

C7 C7 C7 C7 C7

WB11-66 WB11-72 WB18-5 WB18-13 WB18-25 C7 average

25.90 18.40 17.20 21.70 18.30 20.30

14.50 10.67 7.05 9.77 7.14 9.83

7.77 4.97 4.13 7.60 5.67 6.03

0.00 0.00 0.00 0.00 0.73 0.15

3.63 2.76 6.02 4.34 4.76 4.3

15 15 15 15.00

20 10 10 10 16.25

S% denotes the number of smectite layers in illite−smectite phases.

Reservoir Pore Distribution. In order to understand the types of pores present in reservoirs and their distribution as a function of depth (from C3 to C7), more than 100 samples in 3 reservoirs from 8 wells were examined by casting thin sections and SEM imaging. Parameters that were used to measure and characterize pores in each reservoir include pore size, surface porosity (porosity measured in each thin section within an area of 1 in.2), surface area, shape factor, pore throat coordination number, pore sorting, pore-throat size ratio, and percentage of each pore type.41−45 Based on thin section petrography (see Figures 5a, 4b, and 4c), three main types of pores are discovered in Yanchang reservoir rocks: dissolution-enhanced intergranular pores, remnant intergranular pores, and intragranular dissolved pore. Dissolution-enhanced intergranular pores in the reservoir rocks are generally 0.12−0.18 mm in diameter, with an average diameter of 0.15 mm. Remnant intergranular pores are commonly 0.10−0.15 mm in diameter. The size of intragranular dissolved pores, on average, is 0.06 mm in diameter, varying from 0.02 mm to 0.10 mm. Dissolution-enhanced intergranular pores are formed as a product of the dissolution and enlargement of original intergranular pores. Remnant intergranular pores (see Figures 5a and 5b, as well as Table 5) are formed after compaction, dissolution, cementation, and replacement of the original pores.

chlorite, leading to the absence of a C/S mixed layer in reservoirs. Whole-Rock XRD Analyses. Whole-rock XRD analyses were also performed on 21 reservoir samples (see Table 4). The result shows that, among the three reservoirs, the C3 sandstone has the highest quartz content and the C7 sandstone contains the most carbonate minerals, which is consistent with petrographic observations (Figure 5e). Within carbonate minerals, the dolomite content increases from C3 to C7. The dolomite often fills in pores between grains and is sometimes attached to hairlike illitic clay. Ferroan calcite or ferroan dolomite is rarely observed in all three reservoirs. The C6 and C7 reservoirs have a relatively low siderite content (2%−3%), while it is not present in the C3 member. This is consistent with higher clay content in the C6 and C7 reservoir rocks and well-developed shale source rock “Zhangjiatan” in the C7 member, since siderite commonly occurs in beds with shales and clay. Siderite is formed in association with microbial precipitation in anoxia environments. It often coexists with other carbonate minerals, clay minerals, and organic matter.37,38 The occurrence of rhombic-shaped siderite in the C6 and C7 rocks indicates a reducing environment. Overall, the reducing environment in the reservoirs increases with depth (from C3 to C7), which agrees with regional sedimentary depositional environment studies.39,40 112


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Energy & Fuels Table 4. Whole-Rock X-ray Diffraction (XRD) Results of 21 Rock Samples from C3, C6, and C7 Members Composition, According to XRD Results (%) member

sample

clay

quartz

feldspar

potassium feldspar

plagioclase

carbonate

calcite

dolomite

siderite

C3 C3 C3 C3 C3 C3 C3 C3 C3

WB7-9 WB7-33 WB6-59 WB9-8 WB6-24 WB6-9 WB9-24 WB6-39 WB11-5 C3 average

18.00 17.30 8.00 7.80 11.40 10.90 7.00 11.30 10.80 11.98

32.20 29.70 25.9 28.3 28.8 34.8 29.1 30.1 31.60 45.4

42.40 35.90 40.90 60.40 46.10 49.90 53.90 53.30 51.00 32.53

10.50 12.60 5.50 16.70 8.90 13.20 7.10 7.40 13.00 6.46

31.90 23.30 35.40 43.70 37.20 36.70 46.80 45.90 38.00 26.08

7.40 17.10 25.20 3.50 13.70 4.40 10.00 5.30 6.60 10.07

5.80 11.00 25.20 3.50 13.70 4.40 10.00 5.30 5.90 7.27

1.60 6.10 0.00 0.00 0.00 0.00 0.00 0.00 0.70 2.80

C6 C6 C6 C6 C6 C6

WB15-102 WB15-65 WB15-152 WB15-129 WB7-73 WB11-46 C6 average

22.40 12.40 8.90 15.90 20.00 21.00 16.25

56.00 58.00 55.00 43.40 26.00 26.70 33.95

13.90 16.90 23.90 27.90 29.90 30.10 36.08

4.40 6.30 7.50 8.80 9.80 9.00 8.70

9.50 10.60 16.40 19.10 20.10 21.10 27.38

7.70 12.70 12.20 12.80 24.10 22.20 13.73

1.20 3.80 4.50 2.00 9.40 17.90 4.70

6.50 8.90 6.20 10.80 12.30 4.30 7.33

0.00 0.00 1.50 0.00 2.40 0.00 1.70

C7 C7 C7 C7 C7 C7

WB18-30 WB10-10 WB10-33 WB9-31 WB11-71 WB18-3 C7 average

22.30 16.30 14.10 12.60 15.60 15.20 14.47

26.90 44.60 45.90 24.8 24.70 42.30 30.6

40.70 34.90 33.10 47.80 46.40 23.20 39.13

14.00 6.70 10.20 11.80 10.90 9.70 10.80

26.70 28.20 22.90 36.00 35.50 13.50 28.33

6.60 2.80 5.30 14.80 13.30 19.30 15.80

1.00 0.00 1.40 2.00 1.70 16.30 6.67

3.50 0.00 0.00 12.80 8.20 3.00 8.00

2.10 2.80 3.90 0.00 3.40 0.00 1.13

plotted in Figures 5b, 5c, and 5d. Overall, the reservoir permeability increases with increasing percentage of dissolution-enhanced intergranular pores or remnant intergranular pores. The reservoir permeability shows an evident negative correlation with increasing intragranular dissolution pores. The SEM imaging shows that the average pore diameters in the reservoir rocks decrease from C3 (48 μm) to C6 (36 μm) to C7 (33 μm), while the pore throats in each reservoir are similar in size (∼6−7 μm in diameter). A positive correlation between the average pore size and the surface porosity is observed in the studied reservoirs, as also found in conventional reservoirs.46 The C3 member has the highest surface porosity, compared with the C6 and C7 reservoirs. In addition, the pores in the C3 member show the lowest surface area and shape factor, poorest sorting, and largest coordination number (numbers of throats that connect to a single pore). This is a result of the presence of three types of pores with various percentages in the reservoirs (see Table 5). The higher percentage of dissolution-enhanced intergranular pores plus remnant intergranular pores in the C3 member leads to higher permeability and porosity in C3 reservoir rocks than in C6 and C7. Since dissolution-enhanced intergranular pores comprise most pores in all three reservoir rocks, and these pores generally are larger and better connected than remnant intergranular pores and intragranular dissolved pores, dissolution-enhanced intergranular pores are the most important pores in the Yanchang reservoir rocks that contribute to reservoir permeability. Microscopic Pore Structure. Reservoir porosity reflects its storage capacity and permeability reflects its percolation ability. However, both parameters could only reflect an average value

Table 5. Pore Type and Characteristic Parameters of Reservoir Pores Analyzed for 123 Samples from C3, C6, and C7 Reservoirs Value parameter

C3

C6

C7

pore diameter (μm) throat size maximum (μm) minimum (μm) average (μm) porosity (%) average surface area/μm−1 average shape factor average coordination number average pore/throat pore composition (%) remnant intergranular pores dissolution-enhanced intergranular pore intragranular dissolution pore

48.23

36.19

18.01

1.86 6.36 7.58 0.31 0.47 0.48 9.49 9.49

2.10 7.22 4.59 0.42 0.59 0.27 6.16 6.16

1.46 7.21 3.85 0.34 0.53 0.44 7.50 7.50

5.90 77.03 17.55

2.02 72.04 26.07

0.93 70.69 29.51

Intragranular dissolved pores are formed via dissolution within grains. Overall, the dissolution-enhanced intergranular pores are the predominant pores in each reservoir. From C3 to C7, the percentage of dissolution-enhanced intergranular pores decreases from 77.03% to 72.04%, to 70.69%, and the percentage of remnant intergranular pores decreases from 5.90% to 2.02%, to 0.93%. The percentage of intragranular dissolved pores in reservoir rocks increase with depth, from 17.55% to 26.07%, to 29.51% (see Table 5). For each pore type, the relationship between the percentage of pores in the reservoir rocks and reservoir permeability are 113


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Figure 6. (a, c, e) Mercury injection capillary pressure (MICP) curves of 71 samples from C3, C6, and C7 reservoirs in the Triassic Yanchang Formation. (b, d, f) Distribution of the percentage of mercury intrusion into sandstone pores and the contribution of reservoir permeability, as a function of pore throat sizes. Panels (a) and (b) correspond to the C3 member, panels (c) and (d) correspond to the C6 members, and panels (e) and (f) correspond to the C7 member.

member, its pore throat sizes range (in radius) from 0.03 μm to 2 μm. Both C6 and C7 reservoirs, on average, contain smaller pore throats, of which sizes are in narrower ranges (from 0.01 μm in radius to 0.4 μm in radius), so they have comparable good pore throat sorting and are less heterogeneous (see Figures 6c and 6e). The C3 member has higher maximum mercury injection saturation than the C6 and C7 members (see Table 6). The pore throat radii of the C3, C6, and C7 reservoir rocks, with respect to mercury intrusion, show bimodal distributions (see Figures 6b, 6d, and 6f). This suggests that the storage space in the reservoir comes from two groups of pore throats with different sizes: larger pore throats and smaller pore throats, which mainly correspond to dissolution-enhanced intergranular pore and intragranular dissolved pores, respectively. Since remnant intergranular pores are less than ∼5% in reservoir rocks and the sizes are in middle of three types of pores, they contributed to both peaks in the bimodal distributions. At the beginning of mercury injection, the largest pore throats were first intruded by mercury at a relatively low pressure. The value of mercury intrusion is low, suggesting the numbers of large pore throats and total volume of these large throats are small in the system. However, the contribution of

of the large-scale reservoir property; they cannot provide information about the microscopic pore framework.18,47−52 In other words, two reservoirs with same porosity and permeability can consist of pores with very different characteristics (i.e., pore type, structure, geometry, size, and distribution). Therefore, an understanding of the microscopic structure of pores in reservoir rocks is critical to explain the differences in reservoir properties (i.e., porosity, permeability), which result from microscopic variations in pore structures.53−55 The microscale features of pore structures are investigated through mercury injection capillary pressure (MICP) tests on 71 samples, combined with petrographic thin-section observations. As more mercury is injected into the sample, pores that contribute to mercury flow become smaller and the capillary pressure increases. The pore throat data in MICP tests only reflects connected pores and the shapes of capillary pressure curves of each reservoir reflect reservoir pore throat sorting. The capillary pressure curve of the C3 member (Figure 6a) suggests poor sorting and strong heterogeneity of pore throats. The average pore throat sorting coefficients of the C3, C6, and C7 reservoirs are 0.0920, 0.0246, and 0.0202, respectively. The largest sorting coefficient of the C3 reservoir is also consistent with the largest heterogeneity of the pore throats. In the C3 114


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Energy & Fuels Table 6. Measurement of Maximum Intake of Mercury Saturation and Pore Throat Size of the 71 Reservoir Rock Samples

value

maximum pore throat radius (μm)

maximum minimum mean average

2.1726 0.1150 0.5921 0.7080


0.3238 0.0945 0.1368 0.1757


0.2488 0.0334 0.1008 0.1356

average pore throat radius (μm)

mean value of pore throat radius (μm)

C3 Member 0.3103 0.2537 0.031 0.0183 0.0745 0.0794 0.1006 0.0904 C6 Member 0.0505 0.0609 0.0152 0.0105 0.0302 0.0287 0.0334 0.0323 C7 Member 0.0523 0.0621 0.0095 0.0092 0.0237 0.0268 0.0279 0.0266

pore throat sorting number

maximum intake of mercury saturation (%)

0.3427 0.0220 0.0664 0.0920

93.9692 59.6471 89.2057 87.7494

0.0442 0.0118 0.0275 0.0246

93.4278 72.4706 84.4706 84.1050

0.0402 0.0056 0.0145 0.0202

91.4041 64.1176 84.0160 81.6678

Table 7. Porosity and Permeability Measurements of 1232 Samples from Three Reservoir Sandstones value maximum minimum mean average maximum minimum mean average maximum/minimum

C3

C6

Porosity (%) 18.99 12.01 1.47 2.02 11.00 6.70 10.46 6.16 Permeability (mD) 7.6903 0.3941 0.1 0.1 0.245 0.127 0.5996 0.1734 76.9 3.94

C7 13.84 1.00 7.20 5.31 0.3463 0.1 0.102 0.1352 3.46

Reservoir rock petrological analysis, reservoir rock pore distribution, and microscopic pore structure characterization shows that the C3 reservoir has the best reservoir quality.

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DISCUSSION Clastic Rocks Produce Corrosion. The mechanisms for forming secondary porosity are numerous in clastic reservoirs, and the meteoric water leaching and dissolution of feldspar and other unstable minerals caused by carboxylic acid generated from hydrocarbon generation of kerogen can both form secondary porosity.28,54,56−59 A shallow burial depth is characteristic of the reservoir. Dissolution-enhanced intergranular pores are the most developed in the most shallow reservoir of Chang 3, and the secondary dissolution of the sandstone is weakened as one approaches the source rock (Chang 73). The main rock types of Yanchang Formation in Ordos Basin are debris feldspar, feldspar debris, and feldspar sandstone, where the feldspar is the leading component of the Yanchang Formation sandstones. The secondary pores formed by the dissolution of feldspar play a major and constructive role in diagenesis. Strong compaction during early diagenesis in the reservoir leads to reduction of original intergranular pore space, so the reservoir rocks has a very small amount of the remnant intergranular pores. Dissolution processes associated with mechanical compaction produced a large quantity of dissolution enhanced intergranular pores and dissolved intergranular pores in the reservoir. In the study area, the development zone with dissolution-enhanced intergranular pores is the main reservoir distribution area. Effect of Pore Type on Reservoir Properties. From C3 to C7, overall, the permeability has positive correlation with porosity (Figure 7a). However, the permeability and porosity of reservoirs do not follow a simple, uniform relationship. The difference of porosity−permeability relation of each reservoir arises from characteristics of different types of pores that are dominated in each reservoir and their corresponding structure, geometry, size, and distribution. The reservoir rock permeability increases as the percentage of dissolution-enhanced intergranular pores and remnant intergranular pores in the sample increases. The dissolutionenhanced intergranular pores show better correlation with reservoir permeability, compared with remnant intergranular pores (see Figures 7b and 7c), because the dissolutionenhanced intergranular pores are more abundant in the reservoir samples than the remnant intergranular pores. Moreover, the dissolution-enhanced intergranular pores are

these larger pore throats to permeability is very significant. The mercury intrusion value gets much higher when the mercury intrudes into smaller pore throats, because these small pore throats comprise the majority of storage space in the reservoir. However, the contribution of smaller pore throats to permeability is very trivial, because of the existence of large pore throats, the sizes of which are much larger than small pore throats. The reason why the C3 member has higher maximum mercury injection saturation than the C6 and C7 members is due to the presence of larger pore throats that correspond to dissolution-enhanced intergranular pores and remnant intergranular pores (Table 5). For sandstone reservoirs with superlow permeability, the pore throats in the reservoir are primarily very tiny and contribute very little to permeability. Poor pore throat sorting in such reservoir indicates the presence of some larger pore throats, which are better conduits for fluid flow in azenne superlow, nonfractured reservoir. In parallel, good pore throat sorting in this type of reservoir suggests presence of predominant tiny pore throats, tighter reservoir, and thus poorer permeability. Reservoir Petrophysical Properties. Reservoir petrophysical analyses on 1232 samples shows that among the three reservoirs, the C3 reservoir on average has the highest porosity (10.46%) and permeability (∼0.6 mD). The C6 and C7 reservoir has a porosity of ∼5%−6% and a permeability of 0.1− 0.2 mD. The ratio of maximum to minimum permeability in each reservoir suggests the C3 member has the strongest heterogeneity (see Table 7 and Figure 5a). Based on core observation, petrographic thin-section study, and SEM imaging, it is found that the main storage space for oil accumulation in all three reservoirs is microscopic pores and microfractures. Large fractures are not developed in these superlow permeability unconventional sandstone reservoirs; therefore, the permeability of the reservoirs is primarily controlled by different types of pores and their distributions in reservoir rocks. 115


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Energy & Fuels

Figure 7. (a) The relationship between the permeability and porosity of C3, C6, and C7 reservoir rocks. (b) The relationship between the permeability and percentage of dissolution-enhanced intergranular pores of all three reservoirs. (c) The relationship between the permeability and percentage of remnant intergranular pores of all three reservoirs. (d) The relationship between the permeability and percentage of intragranular dissolved pores of all three reservoirs. Data are collected on 41 samples.

formed as a result of the dissolution of original intergranular pores. The connectivity of different types of pores is dependent on the size, geometry, and distribution of the pores. Dissolutionenhanced intergranular pores in the reservoir rocks have the best connectivity, because they have the largest pore sizes among three types of pores and have a more connected distribution in the reservoir. Remnant intergranular pores have mediate connectivity, because they have regular pore sizes and pore geometry. The intragranular dissolved pores have the poorest connectivity, because of tiny pore sizes, irregular pore geometry, and the presence of noneffective pores. In comparison to intragranular dissolved pores in the reservoirs, dissolution-enhanced intergranular pores and remnant intergranular pores would have higher surface porosity, lower surface area, and a lower shape factor, because dissolution-enhanced intergranular pores have more regular shapes and larger pore diameters. Dissolution-enhanced intergranular pores and remnant intergranular pores could be connected with more pore throats (larger coordination number), leading to better pore network connection and higher permeability. In addition, the sizes of dissolutionenhanced intergranular pores and remnant intergranular pore are commonly much larger than that of intragranular pores. Therefore, the most dominant dissolution-enhanced intergranular pores in the reservoir rocks are the most important pores that contribute to the reservoir permeability and the intragranular dissolved pores are the ones that contribute the least to reservoir permeability. The development of dissolution-enhanced intergranular pores and remnant intergranular pores in the reservoir would thus cause poorer sorting of pores and higher microscale heterogeneity, which is an intrinsic factor of large-scale

reservoir heterogeneity. Therefore, the C3 reservoir has the strongest heterogeneity. The porosity and permeability in unconventional tight oil and gas sandstone reservoirs are controlled by many factors (e.g., fractures, pores, rock heterogeneity, etc.). Pore type is a major factor in a nonfractured unconventional sandstone reservoir with superlow permeability. The relationship between the permeability and the porosity of each reservoir from the Yanchang Formation reflects contributions from all three types of pores: dissolution-enhanced intergranular pores, remnant intergranular pores, and intragranular dissolved pores. Complex microscopic pore structures in the superlow permeability sandstone reservoirs make permeability and porosity insufficient to characterize the reservoir. The porosity measurements are not affected by the drag from the existence of microroughness of the pore walls or the minimum distance of fluid flow from one pore to another in the reservoir system. Any change of one or both cases could cause a change in reservoir permeability but not porosity. This is the reason why reservoirs with same porosity often have different permeabilities or small variations in porosity usually correspond to large variations in permeability. Therefore, for superlow-permeability sandstone reservoir rock, detailed characterization of microscopic pore structures in the system, besides porosity and permeability measurements, is necessary. It can improve our knowledge of the reservoir system, guide effective ways for reservoir exploration, and increase reservoir development efficiency. Unconventional sandstone reservoirs with superlow permeability are characteristics of microscopic, disconnected pores, the sizes of which are normally

Comparative Studies of Three Nonfractured Unconventional

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