Lower limit of tight oil flowing porosity: Application of high-pressure mercury intrusion in the fourth Member of Cretaceous Quantou Formation in southern Songliao Basin, NE China

PETROLEUM EXPLORATION AND DEVELOPMENT Volume 42, Issue 5, October 2015 Online English edition of the Chinese language journal Cite this article as: PETROL. EXPLOR. DEVELOP., 2015, 42(5): 745–752.

RESEARCH PAPER

Lower limit of tight oil flowing porosity: Application of high-pressure mercury intrusion in the fourth Member of Cretaceous Quantou Formation in southern Songliao Basin, NE China GONG Yanjie1,2,*, LIU Shaobo1,2, ZHU Rukai1,2, LIU Keyu1,2,3, TANG Zhenxing4, JIANG Lin1,2 1. State Key Laboratory of Enhanced Oil Recovery, Beijing 100083, China; 2. PetroChina Research Institute of Petroleum Exploration & Development, Beijing 100083, China; 3. CSIRO Earth Science and Resource Engineering, Bentley WA 6112, Australia; 4. Jilin Oilfield Company, PetroChina, Songyuan 138000, China

Abstract: According to porosity measured by high-pressure mercury intrusion experiments and helium, and analysis of oil saturation data of 30 samples of tight formations of Member 4 of Cretaceous Quantou Formation in Rangzijing slope zone, southern Songliao Basin, the lower limit of flowing porosity of tight oil and its controlling factors of the samples were determined. By conversion between capillary pressure in reservoir conditions and capillary pressure from high-pressure mercury intrusion experiments, flowing porosity in various injection pressures in reservoir condition can be calculated. By calculating the minimum flowing porosity of oil-bearing samples and the maximum flowing porosity of the samples without oil, it is confirmed that 3.2% is the lower limit of flowing porosity in the oil-bearing samples in the study area; and the corresponding injection pressure in reservoir conditions is 0.35 MPa. If the injection pressure is higher than 0.35 MPa, tight oil can effectively flow and accumulate. The flowing porosity of tight formations and pore-throat ratio are negatively related. When the connectivity of pore-throat in reservoirs becomes poorer, higher injection pressure is needed for flowing porosity to be 3.2%. The injection pressure needed for flowing porosity to be 3.2% have a negative correlation to reservoir quality coefficient. With the reservoir quality coefficient increasing, the injection pressure needed for flowing porosity to be 3.2% has a decreasing tendency. Based on the tight oil lower limit of flowing porosity and injection pressure in reservoir conditions, the discriminant chart of effective accumulation of tight oil was set up. Key words: southern Songliao Basin; Cretaceous; tight oil; lower limit of flowing porosity

Introduction Flowing porosity refers to the ratio of movable fluid volume to rock volume in saturated rock under certain pressure difference[1]. High-pressure mercury intrusion can be used to characterize capillary pressure of tight reservoirs and relationship between minimum wetting-phase saturation[2] or irreducible fluid saturation[3] and capillary pressure, and further determine the corresponding values of movable fluid parameters effectively[4−5]. Therefore, high-pressure mercury intrusion experiment can be conducted to obtain accurate flowing porosity under different mercury injection pressures. In this study, such an experiment was made to determine the lower limit of and controlling factors for flowing porosity of tight oil in the Cretaceous Quan 4 Member in the southern Songliao

Basin. In addition, the template chart to identify effective accumulation of tight oil was prepared, which is of great significance for tight oil evaluation.

1. 1.1.

Experiments and results Experiments

Tight oil has been found in the tight reservoirs of the Cretaceous Quan 4 Member at the slope zone of Ranzijing area in the southern Songliao Basin. For this study, core samples were taken from Well Z59 for high-pressure mercury intrusion experiment (Fig. 1). This full-hole coring well is the only sealing core well in the study area, in which 3 sand-groups with good oil-bearing potential were cored, including 16 cores from Sand-groups 1 and 2, and 14 cores from Sand-group 3.

Received date: 25 Sep. 2014; Revised date: 20 Jul. 2015. * Corresponding author. E-mail: [email protected] Foundation item: Supported by the National Key Basic Research and Development Program (973 Program), China (2014CB239000); China National Science and Technology Major Project (2011ZX05001). Copyright © 2015, Research Institute of Petroleum Exploration and Development, PetroChina. Published by Elsevier BV. All rights reserved.

GONG Yanjie et al. / Petroleum Exploration and Development, 2015, 42(5): 745–752

Fig. 1.

Tight oil distribution of the Cretaceous Quan 4 Member in the southern Songliao Basin.

The high-pressure mercury intrusion experiment was conducted using PoreMasterGT 60, according to the procedures specified in GB/T 21650.1-2008[6], with mercury surface tension of 480 mN/m, mercury contact angle of 140°, dilatometer volume of 0.5 mL, and apparatus’ operating pressure of 0.1−448.0 MPa. The maximum mercury injection pressure ranged in 50−200 MPa in actual measurement, but it was taken as 206 MPa in this experiment. The mercury intrusion curve can reflect the structure of connected pore-throats[7−8]. Moreover, wetting-phase was displaced by non-wetting phase in the mercury injection process. Mercury saturation gradually increased as injection pressure increased to surpass the capillary pressure of smaller pore-throats. 1.2.

Results

The 30 core samples from 3 sand-groups of Well Z59 used in the high-pressure intrusion experiment have a helium porosity of 1.20%−10.30%, calculated porosity of 1.20%−9.05%, and air permeability of (0.01−0.67)×10−3 μm2, representing tight reservoir. The reservoir quality coefficient ( I rq = K φ ) ranges between 0.06 and 0.30. The measured air porosity is equivalent to effective porosity, that is the ratio of interconnected saturated pore-throat volume and rock volume under certain pressure difference[1]. The porosity measured in the high-pressure mercury intrusion experiment is the flowing porosity (namely, the ratio of pore-throat volume calculated by mercury injection volume to rock volume), which refers to the ratio of movable fluid volume to rock volume in saturated rock under a certain pressure difference. Therefore, flowing porosity should be lower than effective porosity[1], which is verified by the two sets of porosity data measured (Table 1) and mainly results from the different interferences on rock surfaces by mercury and air.

The measured porosity is positively correlated with the pore-throat volume per unit mass (Fig. 2a) – the former increases from 1.20% to 9.05% as the later rises from 0.01 to 0.04. The maximum mercury injection pressure varies greatly depending on core samples, from 19.9MPa to 206 MPa. The maximum mercury injection pressure is negatively correlated with average reservoir pore radius (Fig. 2b), in other words, the smaller the average reservoir pore radius, the higher the maximum mercury injection pressure. The maximum mercury injection pressure is around 200 MPa when the average reservoir pore radius is smaller than 0.15 μm, 50−200 MPa when the average reservoir pore radius ranges from 0.15 μm to 0.60 μm, and lower than 50 MPa when the average reservoir pore radius is higher than 0.8 μm.

2.

Discussion

2.1. Mercury injection pressure in the experiment and injection pressure under reservoir conditions The capillary pressure converted from mercury injection pressure in the experiment is different from the capillary pressure under reservoir conditions. These two capillary pressures were converted by assuming that there was little variation in pore-throat radius when the core samples were taken out from reservoir to surface. The coring depth of the samples in this study is 2 110−2 130 m, where the formation has an average geothermal gradient of 4.2 °C/100 m[9], temperature of about 90 °C, pressure coefficient of 0.88−1.10 and formation pressure of 18−20 MPa. The oil-water interfacial tension and water-rock wetting angle are 25.2 mN/m and 0° respectively under the above temperature-pressure conditions. The high-pressure mercury intrusion experiment was performed under room temperature, at which the mercury surface inten-

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Table 1.

Measured porosity and helium porosity of tight core samples taken from the study area.

Sand- Sample group No.

Depth/m

Measured Helium Oil-bearing Sand- Sample porosity/% porosity/% potential group No. 2

Depth/m

Measured Helium Oil-bearing porosity/% porosity/% potential

5

2 038.68−2 038.79

4.23

4.40

Oil trace

77

2 090.28−2 090.45

1.19

1.20

Oil-free

10

2 039.72−2 039.83

4.67

5.80

Oil trace

s71

2 112.34−2112.50

9.05

9.20

Oil trace

15

2 040.45−2 040.58

3.77

4.10

Fluorescence

s75

2 115.55−2115.80

7.22

8.90

Oil patch

24

2 044.64−2 044.74

4.26

4.50

Oil trace

s77

2 115.88−2116.10

7.38

8.00

Oil patch

27

2 045.15−2 045.28

4.50

4.90

Oil patch

s84

2 117.17−2117.40

6.61

7.00

Oil trace

33

2 047.47−2 047.57

5.67

Oil patch

s89

2 118.19−2118.40

3.63

4.90

Oil patch

38

2 048.53−2 048.68

4.57

5.31

Fluorescence

s93

2 119.68−2119.90

7.14

9.30

Oil immersion

41

2 048.90−2 049.01

2.04

2.30

Oil-free

s97

2 120.48−2120.70

5.63

5.60

Oil patch

45

2 054.29−2 054.49

1.68

2.70

Oil-free

s102 2 121.48−2121.80

5.45

6.60

Oil immersion

51

2 061.48−2 061.57

1.58

2.32

Oil-free

s106 2 125.59−2125.90

5.90

8.70

Oil patch

1

2

3

54

2 062.39−2 062.52

1.20

1.94

Oil-free

s109 2 126.29−2126.40

7.50

8.50

Oil trace

57

2 077.00−2 077.13

2.74

3.10

Oil-free

s113 2 127.13−2127.40

6.33

8.10

Oil patch

61

2 077.81−2 077.96

6.08

7.30

Fluorescence

s120 2 128.41−2128.60

8.45

10.30

Oil patch

67

2 078.85−2 079.01

1.49

3.00

Oil-free

s122 2 128.80−2129.00

8.04

8.80

Oil patch

73

2 086.94−2 087.04

2.83

5.10

Oil-free

s128 2 130.02−2130.60

3.46

5.20

Oil patch

Fig. 2.

Correlation of parameters in the high-pressure mercury intrusion experiment.

sion was 480 mN/m and mercury-rock wetting angle was 40°. According to the capillary pressure equation[3]: pc = 2σ cosθ r (1)

The following equation can be got: σ cosθ o pco = o pcm σ m cosθ m

(2)

Then: pco = 0.07 pcm

(3)

The mercury injection pressure can be converted into reservoir injection pressure by using Eq.(3). The mercury injection pressure of core samples in this study ranges from 1.4 MPa to 57.0 MPa, and the converted reservoir injection pressure ranges from 0.1 MPa to 4.0 MPa. Some scholars investigated the source-reservoir injection pressure difference of wells in the study area and believed that tight oil mainly accumulated in areas with source-reservoir pressure difference of 8−12 MPa[10−11]. This figure is much

higher than the calculated reservoir injection pressure (0.1−4.0 MPa), but they are not contradictory. The range of 8−12 MPa is the pressure difference between source rock and reservoir, which is calculated according to interval transit time, but not the actual injection pressure during hydrocarbon charging. According to the law of pressure propagation in the formation[12], the 8−12 MPa pressure difference would reduce to the front pressure of hydrocarbon migration of less than 1 MPa basically after passing through source rocks of several hundred meters thick to reservoir. This agrees with the previous theoretical calculation that hydrocarbon can migrate for 270−340 m at the pressure difference of 8-12 MPa. 2.2.

Lower limit of reservoir flowing porosity

Sample s128 in Sand-group 3 had a flowing porosity of 3.46% and effective porosity of 5.20% at the maximum mercury injection pressure. Sample s89 had a flowing porosity of

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Fig. 3.

Core sample of Sand-group 3 in Well Z59 in 15 days after it was taken out.

3.63% and effective porosity of 4.90% at the maximum mercury injection pressure. However, the oil saturation measured by extraction was up to 48.2%, and both Sample s89 and Sample s128 had high oil-bearing potential in 15 days after they were take out (Fig. 3). Therefore, although the lower limit of effective porosity is defined at 5.5% in the reserve calculation for the study area, the actual lower limit of effective porosity should be lower than 5.5%. The oil saturation of Sample s128 hasn’t been tested, and judging its oil-bearing potential only by oil show is lack of solid data, so the minimum flowing porosity of oil-bearing core samples is taken as 3.63%. The average difference between flowing porosity and effective porosity of Sand-group 3 is 1.24%, and the minimum effective porosity of Sand-group 3 is taken as 4.87%. It should be noted that the lower limit of flowing porosity varies significantly in different areas depending on source-rock thickness, hydrocarbon-generating intensity and fracturedevelopment. In this study, the lower limit of flowing porosity is a constant value, since it is obtained by analyzing the samples from this specific area. The core samples of Sand-group 1 and Sand-group 2 were not tested for oil saturation, but they can be analyzed referring to the oil-bearing potential obtained through core logging. Different from the core samples of Sand-group 3 that reveal oil-bearing potential in whole, the core samples of Sand-group 1 and Sand-group 2 only contain oil in 2 040−2 050 m. The oil-free core samples reflect the maximum flowing porosity of 2.83%. The average difference between flowing porosity and effective porosity of Sand-group 1 and Sand-group 2 is 0.74%, and the maximum effective porosity of oil-free core samples of Sand-group 3 is 3.57%. Therefore, the lower limits of flowing porosity and effective porosity of oil-bearing core samples in the study area are 2.83%−3.63% and 3.57%− 4.87%, respectively. The mean value is generally taken as the lower limit. Thus, the lower limits of flowing porosity and effective porosity of oil-bearing core samples are 3.2% and 4.2%, respectively.

2.3. Reservoir flowing porosity at different injection pressures

Hydrocarbon can not accumulate when the flowing porosity is lower than 3.2%. Most of core samples of Sand-group 1 and Sand-group 2 don’t meet the lower limit of flowing porosity of the study area (Table 1). All core samples of Sand-group 3 are oil-bearing and have flowing porosity higher than 3.2%. Therefore, Sand-group 3 is taken as an example to discuss the relationship between reservoir injection pressure and flowing porosity. According to Eq.(3), the flowing porosity at different mercury injection pressures in the experiment can be converted to the flowing porosity at different reservoir injection pressures. The oil-bearing core samples of Sand-group 3 were analyzed with 5 sets of data at mercury injection pressures of 1 MPa, 3 MPa, 5 MPa, 10 MPa and 15 MPa. Based on Eq.(3), the reservoir injection pressures were determined as 0.07 MPa, 0.21 MPa, 0.35 MPa, 0.70 MPa and 1.05 MPa, respectively. The flowing porosity of core samples in the 2112-2120 m was 1%−5% when the reservoir injection pressure was 0.07 MPa, which indicates quite good reservoir mobility. In contrast, the flowing porosity of core samples in the 2 120−2 130 m interval was basically less than 1%, which indicates poor reservoir mobility. The mobility of most core samples varied when the reservoir injection pressure increased from 0.07 MPa to 0.21 MPa. Generally, the core samples in the 2 112−2 120 m interval had flowing porosity increased to 4%−6%, which is higher than the lower limit of flowing porosity. Therefore, hydrocarbon can accumulate effectively in this interval. However, most of core samples in the 2 120− 2 130 m interval had flowing porosity increased from 1% to about 2%, which indicates limited reservoir mobility (Fig. 4). The core samples in the 2 120−2 130 m interval revealed significantly improved flowing porosity when the reservoir injection pressure increased from 0.21 MPa to 0.35 MPa and 0.70 MPa. Most of these samples had flowing porosity as

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Fig. 4.

Relationships between reservoir injection pressure, flowing porosity and depth.

60%−80% of the limit or as about 3.5% averagely, at reservoir injection pressure of 0.70 MPa, which exceeds the lower limit of flowing porosity. In contrast, the oil-bearing core samples in the 2 112−2 120 m interval slightly varied with the increase of reservoir injection pressure. When the reservoir injection pressure increased from 0.70 MPa to 1.05 MPa, these oil-bearing core samples showed increase of flowing porosity significantly slowed down, but had average flowing porosity increased to 6%−8%, which indicates that the mobility of these samples further improved, and the effective pore volume of tight oil accumulation increased and reached about 90% of the flowing porosity limit. In comparison, the oil-bearing core samples in the 2 120−2 130 m interval didn’t vary greatly. When the reservoir injection pressure increased from 1.05 MPa to the maximum, the flowing porosity varied slightly for most of core samples in the 2 112−2 120 m interval, but significantly for most of core samples in the 2 120−2 130 m interval. Core samples were compared for reservoir injection pressures required when the flowing porosity was 3.2% and 4.8%, respectively, as shown in Fig. 5. In the 3.2% case, the reservoir injection pressures required for all samples were lower than 0.5 MPa, or 0.35 MPa on average, except Sample s89, Sample s97, Sample S113 and Sample s128 (for which, the reservoir injection pressures exceeded 0.5 MPa), indicating that tight oil can effectively accumulate when the reservoir injection pressure reaches 0.35 MPa. In the 4.8% case, the reservoir injection pressures required were less than 0.5 MPa for the core samples in the 2 112−2 117 m interval, and

0.5−2.5 MPa or 0.74 MPa on average for most of core samples in other intervals. Clearly, core samples need different reservoir injection pressures to reach a given flowing porosity. The oil saturation of sealing core samples measured by extraction experiment shows a negative correlation with the reservoir injection pressure at flowing porosity of 3.2% (Fig. 6). Accordingly, oil saturation is 20%−55% when reservoir injection pressure is 0.2 MPa. 2.4.

Controlling factors for flowing porosity

Flowing porosity is an indicator characterizing reservoir mobility. Flowing porosity under different reservoir injection pressures are of great significance for tight oil accumulation. Only this range of porosity can facilitate the effective accumulation of hydrocarbon, and it plays a very important role in tight oil resource evaluation[13−14]. Flowing porosity is not only dependent on accumulation pressure, but also reservoir microstructure. Two key reservoir parameters (pore-throat ratio and reservoir quality coefficient) were matched with flowing porosity in this study (Fig. 7). The pore-throat ratio refers to the ratio of the volume of pores connected by throats to volume of throats, which characterizes reservoir connectivity. The lower the pore-throat ratio (to 1 at lowest) is, the better the reservoir connectivity is. Reservoir quality coefficient reflects reservoir microscopic heterogeneity and smoothness of pore-throat surface. Higher reservoir quality coefficient corresponds to better reservoir heterogeneity and smoother pore-throat surfaces.

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Fig. 5.

Reservoir injection pressure of different core samples when flowing porosity reaches 3.2% and 4.8%.

Fig. 6. Relationship between reservoir injection pressure and oil saturation at flowing porosity of 3.2% (excluding Sample s128).

Fig. 7.

The matching results show that, when the pore-throat ratio is less than 2, there is no apparent correlation between flowing porosity and pore-throat ratio, which suggests that the flowing porosity is mainly controlled by reservoir injection pressure and other reservoir factors in the case of good reservoir connectivity. When the pore-throat ratio exceeds 2, the flowing porosity negatively correlates with the pore-throat ratio, suggesting a poor reservoir connectivity, where the flowing porosity is mainly controlled by the pore-throat ratio. When the reservoir quality coefficient is lower than 0.1, the flowing porosity is generally low and not more than 5%. When the reservoir quality coefficient is higher than 0.1, there is a weak

Matching relationships between pore-throat ratio, reservoir quality coefficient and flowing porosity.

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Fig. 8. Relationships between reservoir injection pressure and pore-throat volume ratio or reservoir quality coefficient at flowing porosity of 3.2%.

positive correlation between flowing porosity and reservoir quality coefficient (Fig. 7). when the flowing porosity reaches 3.2%, there is a clearly positive correlation between reservoir injection pressure and pore-throat ratio (Fig. 8a), which shows that higher reservoir injection pressure is needed to enable the flowing porosity to reach 3.2% when the reservoir pore-throat connectivity gets poorer, in other words, reservoir microscopic mobility is affected by the pore-throat ratio. There is a negative correlation between reservoir injection pressure needed to reach flowing porosity of 3.2% and reservoir quality coefficient (Fig. 8b), in other words, the reservoir injection pressure needed to reach flowing porosity of 3.2% decreases with the increase of reservoir quality coefficient. Based on the above research, the template chart to identify effective accumulation of tight oil in the study area was prepared (Fig. 9), in which the two blue curves represent reservoir injection pressure and flowing porosity of different core samples respectively. When the flowing porosity and reservoir injection pressure are higher than 3.2% and 0.35 MPa respectively, tight oil can effectively accumulate, and the area with these characteristics is identified as an effective accumulation area. When the reservoir injection pressure is lower than 0.35 MPa, tight oil cannot effectively accumulate in Category A core samples due to insufficient injection pressure. Since the flowing porosity of Category B core samples is lower than the lower limit of flowing porosity, tight oil cannot effectively accumulate in these samples no matter how high the reservoir

injection pressure is. All the oil-bearing core samples of 3 sand-groups in the study area belong to Category A, while the oil-free core samples belong to Category B.

3.

Conclusions

High-pressure mercury intrusion can be used to obtain the flowing porosity at different mercury injection pressures accurately. Considering actual geology of the study area, the capillary pressure measured in high-pressure mercury intrusion experiment can be converted into reservoir capillary pressure, so that flowing porosity at different reservoir injection pressures can be calculated. Reservoir flowing porosity is greatly affected by injection pressure, pore-throat ratio and reservoir quality coefficient. Reservoir microscopic mobility decreases with the increase of pore-throat ratio. With the increase of reservoir quality coefficient, injection pressure needed to reach flowing porosity of 3.2% decreases. The lower limit of flowing porosity is defined as 3.2% by calculating the minimum flowing porosity of oil-bearing core samples and the maximum flowing porosity of oil-free core samples, and the corresponding lower limit of effective porosity is 4.2%. When the lower limit of flowing porosity of the study area is 3.2%, the corresponding reservoir injection pressure is 0.35 MPa. Tight oil can effectively accumulate when reservoir injection pressure exceeds 0.35 MPa. On this basis, the template chart to identify effective accumulation of tight oil has been prepared.

Acknowledgements The authors would like to express their gratitude to Professor Zou Caineng, Professor Zhao Mengjun, Professor Yuan Xuanjun, Professor Tao Shizhen with PetroChina Research Institute of Petroleum Exploration and Development, and Jiang Tao, Deng Shouwei, Yang Liang, Huang Mingzhi and others with PetroChina Jilin Oilfield Company for their help and guidance.

Nomenclature Fig. 9. Template chart for identification of effective tight oil accumulation.

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K—permeability, μm2;

GONG Yanjie et al. / Petroleum Exploration and Development, 2015, 42(5): 745–752

φ—porosity, %; pc—capillary Pressure, Pa; pcm—capillary pressure of high-pressure mercury intrusion ex-

Part 1: Mercury porosimetry. Beijing: Standards Press of China, 2008. [7]

Xie Wuren, Yang Wei, Yang Guang, et al. Pore structure features of sandstone reservoirs in the Upper Triassic Xujiahe

periment, Pa;

pco—reservoir capillary pressure, Pa;

Formation in the central part of Sichuan Basin. Natural Gas Geoscience, 2010, 21(3): 435–440.

r —pore-throat radius;

σ —oil-water interfacial tension, N/m; σm—mercury surface tension in the high-pressure mercury intru-

[8]

Zhang Manlang, Li Xizhe, Xie Wuren. Pore types and pore texture of sandstone reservoir of 2nd member of Shanxi Formation, Ordos Basin. Natural Gas Geoscience, 2008, 19(4):

sion experiment, N/m;

θ —water-rock wetting angle, (°); θ o—reservoir water-rock wetting angle, (°); θ m—mercury-rock wetting angle in the high-pressure mercury intrusion experiment, (°).

480–486. [9]

Guo Wei, Fang Shi, Liu Zhaojun, et al. Study on the thermal evolution history of the Quantou and Nenjiang Formation in the southern Songliao Basin. Journal of Oil and Gas Technology, 2009, 31(3): 1–6.

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