Physical-property cutoffs of tight reservoirs by field and laboratory experiments: a case study from Chang 6, 8–9 in Ordos Basin

Abstract

Tight sandstone reservoirs are generally characterized by complex reservoir quality, non-Darcy flow, and strong heterogeneity. Approaches utilized for evaluating physical property cutoffs of conventional reservoirs maybe inapplicable. Thus, a comprehensive investigation on physical property cutoffs of tight sandstone reservoirs is crucial for the reserve evaluation and successful exploration. In this study, a set of evaluation approaches take advantage of field operations (i.e., core drilling, oil testing, and wireline well logging data), and simulation experiments (i.e., high-pressure mercury injection-capillary pressure (MICP) experiment, oil-water relative permeability experiment, nuclear magnetic resonance (NMR) experiment, and biaxial pressure simulation experiment) were comparatively optimized to determine the physical property cutoffs of effective reservoirs in the Upper Triassic Chang 6, Chang 8 and Chang 9 oil layers of the Zhenjing Block. The results show that the porosity cutoffs of the Chang 6, Chang 8, and Chang 9 oil layers are 7.9%, 6.4%, and 8.6%, and the corresponding permeability are 0.08 mD, 0.05 mD, and 0.09 mD, respectively. Coupled with wireline well logging, mud logging, and oil testing, the cut-off of the thickness of single-layer effective reservoirs are approximately 3.0 m, 3.0 m, and 2.0 m, respectively. Depending on the cutoffs of critical properties, a superimposed map showing the planar distribution of the prospective targets can be mapped, which may delineate the effective boundary of prospective targets for petroleum exploration of tight sandstone reservoirs.

Key words： tight sandstone reservoirs; cutoffs of petrophysical property; field operations; simulation experiments; Yanchang Formation; Ordos Basin

1 Introduction

With advances in oil and gas exploration technology, tight sandstone deposits have manifested great potential for extraction (Law and Curtis, 2002; Makhloufi et al., 2013; Yang et al., 2013; Wang et al., 2017a; Cui et al., 2019; Li et al., 2019c; Pang et al., 2019, 2020a and 2020b). By the end of 2016, China’s established continental tight oil production capacity reached 1.553 × 10⁶ tons (Hu et al., 2018). With the deepening exploitation of tight sandstone reservoirs, the physical property cut-off of the exploitation is gradually decreased to the critical conditions of the oil charging. And it is becoming increasingly important for the accurate determination of the physical property cut-off of the tight sandstone reservoirs. Tight sandstone reservoirs are widely developed in the Upper Triassic Yanchang (T₃y) Formation of the Zhenjing Block (Chang 6, Chang 8, and Chang 9 oil layers), south-western Ordos Basin. Previously, numerous successful studies have been conducted on the Yanchang Formation, which effectively guided the exploration and development of tight sandstone reservoirs (Liu et al., 2013; Li et al., 2017a, 2017b and 2019a; Wang et al., 2017a and 2017b; Yang et al., 2017; Shi et al., 2019, 2020a; Liu et al., 2020a). However, previous researches of tight oil reservoirs primarily focus on the reservoir densification process, physical properties, fluid seepage characteristics, macroscopic pore geometries, and the distribution law of tight reservoirs, especially on the cutoffs of petrophysical properties (Worthington, 2008 and 2010; Masoudi et al., 2014; Worthington and Majid, 2014; Wang et al., 2015a; Gong et al., 2016; Zhou et al., 2016; Rostami et al., 2019; Li et al., 2019b and 2020; Zheng et al., 2020).

In recent years, research approaches for determining physical property cutoffs of conventional reservoirs have widely been investigated, various sets of approaches were proposed including physical properties, field operations (i.e., core drilling, oil testing, and wireline well logging data), and simulation experiments (i.e., high-pressure mercury injection capillary pressure (MICP) experiment, oil-water relative permeability experiment, nuclear magnetic resonance (NMR) experiment, stress sensitivity experiment, and biaxial pressure simulation experiment), and based on dynamic mechanism of tight oil reservoir accumulation to distinguish the cutoffs of the petrophysical properties of conventional reservoirs. (Hohn, 1989; Kikani and Pedros, 1991; Pittman, 1992; David et al., 1994; Wan et al., 1999; Wei et al., 2005; Worthington and Cosentino, 2005; Peng et al., 2009).

Besides, the upper limits of petrophysical parameters have been found to be consistent (porosity<10% and overburden matrix permeability<0.1 mD; Holditch, 2006; Aguilera, 2014; Zou et al., 2009 and 2012a). However, an issue directly related to the exploration and development of tight sandstone reservoirs remains in that the cutoffs of tight sandstone reservoirs has not been clearly understood thus far. Therefore, a universally approach that is more accurate, in accordance with the actual formation conditions, and considers the economic benefits to calculate the cut-offs of petrophysical property of tight sandstone reservoirs is lacking. With the extensive research on the micro-pore structure and seepage characteristics of tight sandstone reservoirs, conventional and distinct research approaches have highlighted numerous problems in the characterization of tight sandstone reservoirs (Masters, 1979; Gies, 1984; Wang et al., 2008; Dai et al., 2012; Zou et al., 2012a and 2012b; Baytok and Pranter, 2013; Jia et al., 2016; Guo et al., 2017; Qiu et al., 2017; Tan et al., 2017; Liu et al., 2020b). With the gradual densification of tight sandstone reservoirs under the deep-burial condition, tight reservoirs developed unique pore structure and fluid seepage characteristics. Thus, several approaches mentioned above for determining the cutoffs of conventional reservoirs maybe inapplicable to the evaluation of tight sandstone reservoirs (Shi et al., 2015).

In this study, in the consideration of the characteristics of complex reservoir quality, non-Darcy flow, strong heterogeneity, and micro-pore throats of tight sandstone reservoirs, using the preferred approaches for comprehensive delineated the cutoffs of tight sandstone reservoirs. Combined with the cut-off of the thickness of single-layer effective reservoirs, we obtain a congruent map showing the planar distribution of prospective targets, which may delineate the effective boundary of prospective targets for petroleum exploration of tight sandstone reservoirs. The preferred approaches are of profound significance for resource evaluations of tight oil reservoirs and the selection of exploration zones.

2 Geological settings

The Zhenjing Block is situated in the southern part of the Tianhuan Depression, south-western Ordos Basin, China (Fig. 1(a)), which is in the transition area between the north-westward depression and its south-western nose-shaped uplift. The isopach map showing the top of T₃y Formation is featured by structural west high and east low (Fig. 1(b)).

Fig.1 Map showing the (a) regional location and (b) isoline showing the top of Yanchang Formation of the Zhenjing Block, Ordos Basin.

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The T₃y Formation, deposited from the Carnian stage to the Norian stage, is subdivided into 10 intervals from bottom to top (Chang 10 to Chang 1), but wireline well logging data show that the Chang 3 and Chang 4+ 5 layers are generally missing in the study area. All the intervals consist of sandstones, mudstones, and shales, among which the Chang 7 oil layer is composed predominantly of oil shales and black mudstones; the other intervals are composed of sandstones and mudstones (Fig. 2(a)). Therefore, Chang 7 oil layer serves as the source rock and seal for the underlying Chang 9 and Chang 8 and overlying Chang 6 oil layers. Chang 6, Chang 8, and Chang 9 oil layers have been identified as important exploration targets, and important progress has been made in exploration in recent years (Fu et al., 2014). At present, up to 18005 × 10⁴ tons of proven oil reserves have been identified in the Zhenjing Block. Specifically, proven oil reserves of the Chang 6, Chang 8, and Chang 9 oil layers account for 99.0%, and the others account for only 1.00% (147.7 × 10⁴ tons), revealing that the Chang 6, Chang 8, and Chang 9 oil layers are main oil-producing horizons of the Zhenjing Block. The proven oil reserves of the Chang 8, Chang 9, and Chang 6 oil layers are 14211 × 10⁴ tons, 3645 × 10⁴ tons, and 356 × 10⁴ tons, respectively, accounting for 79.0%, 18.0%, and 2.0% (Fig. 2(b)).

Fig.2 Comprehensive (a) stratigraphic column and (b) pie chart of abundance of reserves of the Chang 6, Chang 8 and Chang 9 oil layers of the Zhenjing Block, Ordos Basin. Notes: T₃y: Upper Triassic Yanchang Formation; J_1-2y: Lower to Middle Jurassic Yan’an Formation.

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Sandstones are classified according to the method of Folk et al. (1970). Based on the analysis of rock slices of 30-seven wells in the study area (Fig. 3(a)), from Chang 6, Chang 8 to Chang 9, the contents of quartz decreased from 60.9% to 32.6% on average, contents of feldspar and rock fragments increased from 39.1% to 67.4% on average, and corresponding average composition of the framework grains from Q_60.9F_22.0R_17.1 to Q_32.6F_39.3R_28.1. As showed in Fig. 3(b), with increasing depth, the contents of volcanic rock fragments increased and metamorphic rock fragments decreased.

Fig.3 Ternary diagram showing the (a) framework compositions and (b) detrital components of the Chang 6, Chang 8 and Chang 9 tight sandstones in the Zhenjing Block. Notes: Q: quartz; F: feldspar; RF: rock fragments; VRF: volcanic rock fragments; MRF: metamorphic rock fragments; SRF: sedimentary rock fragments.

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3 Sample selection and experiments

3.1 Samples preparations and materials

In this study, the core samples, wireline well logging, oil testing data of the Chang 6, Chang 8, and Chang 9 oil layers of 25 wells in the Zhenjing Block were collected from the SINOPEC Petroleum Exploration and Production Research Institute, Beijing. All samples used in this study were taken from more than 270 m well cores and 1220 thin sections of the 25 wells at the depths of 1781–2172 m in the Zhenjing Block were observed (Fig. 1(b)).

3.2 Petrophysical property analysis

The samples were collected for porosity and permeability testing using cylinders of 2.5 cm diameter and 5 cm length (the relevant petrophysical property data used in this study can be seen in Supplementary data). All the cylinders were drilled along the horizontal direction of the cores. Porosity was measured on a JS100007 helium porosimeter and permeability was measured on an A-10133 gas permeameter using standard industry methods. Both the helium porosimeter and gas permeameter were manufactured by Micromeritics Instrument (Shanghai) Ltd.

3.3 Grain-size analysis

The compositions of the Chang 6, Chang 8, and Chang 9 sandstones were determined by point counts of at least 200 grains per thin section. Grain sizes were measured from the photomicrographs of thin sections using Image-Pro Plus software (Media Cybernetics), with the manual function, and each of the photomicrographs had at least 160 grains.

3.4 Simulation experiments

In this study, an integration of stress sensitivity analysis, high-pressure mercury injection capillary pressure (MICP) experiment, oil-water relative permeability test, and nuclear magnetic resonance (NMR) experiment, together with biaxial pressure simulation experiment were analyzed for determining the cutoffs of petrophysical property of tight sandstone reservoir.

Stress sensitivity analysis of 13 core samples was conducted using a PoroPDP-200 type instrument to measure porosity and permeability by the pulse method under overburden stress, according to the requirements of the industry standard for stress sensitivity experiment (SY/T5358-2002,≥1mD). The gas employed for the porosity test was helium and, for the permeability test, nitrogen. When measuring permeability, the overburden stress was initiated at 0.0 MPa and gradually increased until the confining pressure was maximized at 55.0 MPa. The overburden stress was later gradually reduced.

The MICP experiment was conducted on 218 samples from 24 wells using a Pore Sizer 9320 mercury porosimeter manufactured by Micromeritics Instrument (Shanghai) Ltd. to confirm pore-throat radius and displacement pressure.

The unsteady-state displacement approach was utilized to determine the oil-water relative permeability (Esmaeili et al., 2019; Wang et al., 2015b and 2019). An immiscible displacing fluid (formation water with a salinity of 85000 mg/L) was injected at a constant rate to replace crude oil (viscosity of 2.80 mPa∙s) in situ to the highest possible saturation in core samples in the laboratory. The transient behavior of the pressure drop across the length of the core and the volumes of the produced phases were recorded periodically, and the oil-water relative permeability characteristics were inferred from the recorded production and pressure drop history of the displacement test.

NMR measurements combined with centrifugal experiments were performed using a UNIQ PMR nuclear magnetic resonance analyzer (Beijing Yongshengtong Technology Development Co., Ltd.) to obtain the transverse relaxation time (T₂) spectrum of nine wells. Samples were collected every 0.30–0.50 m for intervals with oil and gas, and samples were collected every 0.50 m for intervals without oil and gas. First, the NMR measurements of nine wells were performed on samples in the fully water-saturated state (brine with 41000 ppm). Then, the movable water in the samples was centrifuged by a centrifuge machine and the NMR measurements were performed in the irreducible water state. The centrifugal pressure was set up as 600psi for tight sandstone samples, and the duration was set up as one hour. In the NMR experiment, the saturation of the movable fluid is utilized to calculate the porosity (ϕ_nmr), and the permeability (K_nmr) is obtained using the following Eq. (1) (Adebayo et al., 2020; Zhang et al., 2020).

(1)K_{\mathrm{nmr}}=C·{\phi }_{\mathrm{nmr}}^{\mathrm{2}}·T_{\mathrm{2}}^{\mathrm{2}},

where K_nmr: cuttings permeability, mD; ϕ_nmr: cuttings porosity, %; C: 0.5.

Liu et al. (2012a and 2012b) proposed a biaxial pressure simulation experiment to study the critical conditions of the oil charge (Fig. 4(a)). In this study, 34 core samples of the Chang 6 and Chang 8 oil layers were prepared as cylindrical rock plugs of 2.5 cm diameter and 4–6 cm length. For the simulated formation fluids, a saturated solution of NaCl with a salinity of 49600 × 10⁻³ mg/L and T60 lubricant with a resistivity of 0.1368 W·m (25°C) and a relatively high viscosity were used. By exerting confining pressure (σ₁) and axial pressure (σ₂) on the core samples to simulate its stress state under different burial-depth conditions, the simulated formation fluid was charged into the cores to simulate the oil charging process (Fig. 4(b)). After charging the simulated formation fluid, the resistivity value monitored by the RLC bridge increased dramatically. In this study, the preliminary value of σ₁ was 5 MPa, and a set of minimum charging pressure values was monitored for each increase in σ₁ (simulated burial-depth increase). In theory, 8 sets of data can be collected when the confining pressure is increased to a maximum of σ₁ (40 MPa). σ₂ is determined using Eq. (2) (Liu et al., 2012a and 2012b):

(2){\sigma }_{\mathrm{2}}={\sigma }_{\mathrm{1}}\times \gamma /(\mathrm{1}-\gamma ),

where σ₁: confining pressure, MPa; σ₂: axial pressure, MPa; γ: dynamic Poisson ratio.

Fig.4 Experimental apparatus for biaxial pressure simulation experiment. Notes: σ₁: confining pressure; σ₂: axial pressure (modified after Liu et al., 2012a and 2012b).

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4 Results and discussion

4.1 Inapplicability of determining the cut-off of the tight reservoir based on petrophysical properties

Numerous previous studies demonstrated the evaluation criteria are based on large amounts of petrophysical property data, and rules are based on collections of empirical statistics to distinguish the cutoffs of conventional reservoirs (Hohn, 1989; Wan et al., 1999; Wei et al., 2005; Jiao et al., 2009; Li et al., 2017b; Jing et al., 2020). Traditionally, the physical properties of the conventional reservoir were featured by a normal distribution (Figs. 5(a)–5(c)) and logarithmic correlation (Fig. 5(d)). Owing to the gradual densification of tight sandstone reservoirs, which result in strong heterogeneity and the development of micro-cracks, the development of micro-cracks may enlarge the seepage capacity (Eq. (3)), making the petrophysical properties shown as skewed distribution (Figs. 5(e)–5(g)), and making the relationship between the porosity and permeability more complicated (Fig. 5(h), the relevant petrophysical property data used in this study can be seen in Supplementary data).

(3)Q_{Ki}={\displaystyle \frac{K_i·h}{{\displaystyle \sum K_i·h_i}}},

where Q_Ki: oil production capacity of the ith sample, %; K_i: permeability of the ith sample, mD; h_i: length of the ith sample, m.

Fig.5 Schematic diagram showing the difference of petrophysical property between (a–d) conventional reservoir and (e–h) tight sandstone reservoir (Wan et al., 1999; Wei et al., 2005; Jiao et al., 2009).

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4.2 Inapplicability of determining the cut-off of the tight reservoir based on stress sensitivity experiment

In previous studies, some scholars proposed the evaluation criteria based on stress sensitivity experiments (Peng et al., 2009; Cui et al., 2017; Rostami et al., 2019; Shi et al., 2020a). However, because the upper limits of permeability of tight sandstone reservoirs are lower than 1 mD, which is lower than the requirements of the industry standard for stress sensitivity experiment (SY/T5358-2002, ≥1 mD). Moreover, tight sandstone reservoirs have undergone intense compaction and gradual densification within the deep-burial condition. As such, the results of stress sensitivity experiments of 13 samples show that with the increase of overburden pressure, permeability and porosity decrease (Fig. 6), and the range within which permeability decreases is greater than those of porosity, which reveals that the permeability is more sensitive to overburden stress than the porosity. Besides, the larger the initial permeability is, the greater the range decreases; while when the initial value is very low, the decrease range is limited. Increasing the pressure only causes little changes in stress, leading to large errors (Fig. 6). Hence, the method based on the stress sensitivity experiment does not recommend for tight sandstone reservoirs.

Fig.6 Stress sensitivity analysis for the Chang 6–9 oil layers in the Zhenjing Block.

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4.3 Redefining the cutoffs of physical properties of tight sandstone reservoirs based on field operations

According to grain-size analysis and oil-bearing occurrence data derived from core observation of the Chang 6, Chang 8 and Chang 9 oil layers, the oil-bearing occurrences of fine- to medium-sandstones are mainly oil spots to oil immersions, while siltstones and argillaceous siltstones and mudstones generally do not show fluorescence. In particular, gritstone is unfavorable for the preservation of crude oil due to its large grain size and small specific surface area (Figs. 7(a)–7(c)). These findings revealed that the lithology of the effective reservoir is fine-medium sandstone. As shown in Figs. 7(d)–7(f), there is a good correlation between the petrophysical properties and the oil-bearing occurrences of the tight sandstone reservoirs. In general, the oil-bearing occurrence of commercial oil flow wells generally reaches the levels of oil traces to oil spots. As shown in Figs. 7(d)–7(f), the cutoffs of the porosity of effective reservoirs in the Chang 6, Chang 8 and Chang 9 oil layers are 8.0%, 3.0%, and 11.5%, and the corresponding permeability are 0.10 mD, 0.20 mD, and 0.20 mD, respectively. The sweet spot, generally is those reservoir rocks that are characterized by relatively high-quality greater than the average values of tight gas sands at a specific depth interval. The oil-bearing occurrences of the “sweet spot” generally reached to oil-spot, and exhibited commercial exploration potential (Khlaifat et al., 2011; Stabell, 2013; Wang et al., 2020a and 2020b; Zhao et al., 2020). Correspondingly, the cutoffs of “sweet spot” in the Chang 6 and Chang 9 oil layers are 9.0%, 4.0% and 17.0%, 0.3 mD, 0.3 mD and 1.0 mD, respectively.

Fig.7 Comprehensive determination of the cutoffs of the petrophysical property of the Chang 6, Chang 8 and Chang 9 oil layers using field data.

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In this study, wireline well logging interpreted data are also utilized to distinguish the cutoffs of physical properties of the commercial layer (i.e., oil layer, oil-bearing water layer, water layer, and oil-water layer) and non-commercial layer (i.e., dry layer and poor oil layer, Wan et al., 1999; Jiao et al., 2009; Fu et al., 2014). According to the wireline well logging interpreted results of eight wells in the studied area, the cutoffs of the porosity of effective reservoirs in the Chang 6, Chang 8, and Chang 9 oil layers can be considered as 8.0%, 9.5%, and 7.0%, respectively (Figs. 7(g)–7(i)).

4.4 Redefining the cutoffs of physical properties of tight sandstone reservoirs based on simulation experiments

4.4.1 High-pressure mercury injection capillary pressure experiment

Results of the MICP test revealed that Chang 6, Chang 8, and Chang 9 have different pore-structure characteristics (Fig. 8(a)). The displacement pressure value of Chang 6, Chang 8, and Chang 9 ranges from 0.78 MPa to 0.96 MPa, 1.00 MPa to 1.62 MPa, and 0.81 MPa to 6.45 MPa, respectively. The median pressure value of Chang 6, Chang 8, and Chang 9 range from 3.65 MPa to 5.44 MPa, 5.43 MPa to 47.52 MPa, and 12.05 MPa to 33.32 MPa, respectively, and the corresponding median radius are 0.01–22.45 mm, 0.20 mm, and 0.01–0.06 mm, respectively. Values of mercury withdrawal efficiency range from 29.21% to 34.16%, 23.80% to 43.64%, and 20.80% to 39.54% for Chang 6, Chang 8, and Chang 9, respectively. Such differences in the characteristics of the pore-throat imply that the cutoffs of the Chang 6, Chang 8, and Chang 9 oil layers are distinct.

Fig.8 (a) Morphology characteristics of mercury injection curves and (b) the cross-plot of mercury saturation versus normalized “J”-function of Chang 6, Chang 8 and Chang 9 oil layers in the Zhenjing Block.

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In this study, normalized dimensionless Leverett function (“J”-function, Eq. (4)) of capillary pressure was applied based on the results of the MICP test (Leverett, 1941; Abedini and Torabi, 2015; Fig. 8b).

J\left(S_{\mathrm{H}\mathrm{g}}\right)={\displaystyle \frac{P_{\mathrm{c}}}{\sigma }}·\sqrt{{\displaystyle \frac{k}{\phi }}}=\mathrm{0.086}{P}_{\mathrm{c}}·{(k/\phi )}^{-\mathrm{1}/\mathrm{2}}

(4)=\mathrm{0.0636}{S}_{\mathrm{H}\mathrm{g}}^{\mathrm{0.7509}},

where, J: Leverett function; S_Hg: water saturation, %; P_c: capillary pressure, MPa; σ: surface tension, N/m; k: permeability, mD; ϕ: porosity, %.

Cumulative permeability method to calculate the minimum flow pore throat radius as seen in Eq. 5. When the cumulative permeability contribution value reaches 99.0%, the corresponding pore throat radius is the minimum flow pore throat radius (Ye et al., 2019). Based on the “J”-function, the minimum flow pore throat radius of the Chang 6, Chang 8 and Chang 9 oil layers is 0.017 mm.

(5)k={\displaystyle \sum }\mathrm{\Delta }{k}_i={\displaystyle \sum \left[{\displaystyle \frac{\phi ({\mathrm{2}}^i-\mathrm{1})r_n^{\mathrm{2}}}{{\displaystyle \sum _{i=\mathrm{1}}^n({\mathrm{2}}^i-\mathrm{1})r_i^{\mathrm{2}}}}}\right]\times \mathrm{100}},

where, k: cumulative permeability, mD; Δk_i: contribution value of permeability in ith interval, mD ; r_i: corresponding throat radius of ith interval.

Cross-plots of the throat radius versus permeability (Figs. 9(a)–9(c)) proves that the cutoffs of the effective reservoir for the Chang 6, Chang 8, and Chang 9 oil layers are 0.05 mD, 0.03 mD, and 0.15 mD, respectively.

As shown in Figs. 9(d)–9(f), there is a good correlation between the displacement pressure versus permeability, manifested as an obvious curve inflection point, which is represented as the cut-off of physical properties of tight sandstone reservoirs (Figs. 8(d)–8(f); Pittman, 1992; Jiao et al., 2009; Fu et al., 2014). When the permeability is less than the inflection point, the values of displacement pressure increase rapidly. And when the permeability is higher than the inflection point, the values of displacement pressure do not change significantly. As shown in Figs. 9(d)–9(f), the cutoffs of permeability of effective reservoirs in the Chang 6, Chang 8, and Chang 9 oil layers are 0.10 mD, 0.05 mD, and 0.10 mD, respectively.

Fig.9 Comprehensive determination of the cutoffs of the petrophysical property of the Chang 6, Chang 8 and Chang 9 oil layers through simulation experiments. Notes: The green line shown in Figs. 9(a)–9(c) represent the minimum flow pore throat radius; the red line shown in Figs. 9(d)–9(f) represent the cutoff of permeability of effective reservoir.

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4.4.2 Oil-water relative permeability experiment

As seen in oil-water relative permeability curves, the lower inflection point of the oil phase permeability curve is considered as the cut-off of effective reservoirs (Peng et al., 2009; Cui et al., 2017; Rostami et al., 2019). The inflection point of the oil phase permeability curve approaches from the intersection point of oil and water phase permeability. Therefore, the intersection point can be considered as the cut-off of effective reservoirs (Shi et al., 2020a). As shown in Figs. 8(g)–8(i), the intersections of the oil-water relative permeability curves of eight wells indicated that the cut-off of permeability of effective reservoirs in the Chang 6, Chang 8, and Chang 9 oil layers are 0.09 mD, 0.05 mD, and 0.05 mD, respectively.

4.4.3 Nuclear magnetic resonance experiment

Movable fluid saturation is an important indicator for evaluating the physical properties and determining the cut-off of tight sandstone reservoirs (Zhang et al., 2020). The T₂ distributions in the irreducible and movable fluid states can be used to characterize the irreducible and movable fluid micro-distribution, respectively. The T₂ distribution in the fluid-saturated state represents the comprehensive response of the irreducible fluid and the movable fluid in the pores. Hence, based on the cut-off standard of saturation of the movable fluid of the Langfang State Key Laboratory (>10%), the results of a gas displacement test of core samples from seven wells indicated that the cut-off of cutting permeability of Chang 6, Chang 8, and Chang 9 are 0.0824 mD, 0.0347 mD, and 0.0063 mD, and the corresponding movable fluid saturations are 16.98%, 10.80%, and 24.15%, respectively (Figs. 8(j)–8(l)).

4.4.4 Biaxial pressure simulation experiment

The results of the biaxial pressure simulation experiment demonstrate that most core samples of the Chang 6 oil layer can be injected with oil under high fluid pressure. Except for one sample of the Chang 8 oil layer (well ZJ18-4), in which oil could be injected under high fluid pressure, the other 20 samples could not be injected with oil even at the maximum filling fluid pressure (30 MPa/m) (Fig. 10). The comparison between the filling results and core physical data shows that when the core porosity is less than 10.5% and the permeability is less than 0.34 mD, oil cannot be injected even if the filling pressure is increased to the maximum value. Based on this, the cut-off of porosity of the Chang 6 and Chang 8 oil layers is 10.5%, and the corresponding cut-off of permeability is 0.34 mD.

Fig.10 Cross-plots of differences in critical charging pressure versus burial depth of the Chang 6, Chang 8 and Chang 9 tight sandstones in the Zhenjing Block.

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4.5 Assessment of the cutoffs of physical properties of tight sandstone reservoirs by oil testing data

The comprehensive analysis has shown that the average of cutoffs of permeability of the Chang 6, Chang 8, and Chang 9 are 0.08 mD, 0.05 mD, and 0.09 mD, respectively, and the corresponding the average of cutoffs of porosity of the Chang 6, Chang 8, and Chang 9 are 7.9%, 6.4%, and 8.6%, respectively. According to petroleum industry standards of China, when the oil layer is buried at depths of 1000–2000 m, the daily oil yield must be>1 tons/d, which corresponds to the industrial oil layer, and when the oil layer is buried at depths of 2000–3000 m, the daily oil yield must be>3 tons/d, which also corresponds to the industrial oil layer (SY/T 6293-2008). Figure 11 shows cross-plots of the daily oil yield versus permeability (Figs. 11(a)–11(c)) and daily oil yield versus porosity (Figs. 11(d)–11(f)) of the Chang 6, Chang 8, and Chang 9 oil layers in the Zhenjing Block. When the above values are taken, the minimum daily oil yield of the effective reservoir is>4 tons/d, which is consistent with the standard of commercial oil flow of tight sandstone reservoirs.

Fig.11 Cross-plots showing daily oil yield versus permeability (a–c) and daily oil yield versus porosity (d–f) of the oil-bearing intervals of the Chang 6, Chang 8 and Chang 9 oil layers in the Zhenjing Block. Note: The red line represent the cutoff of permeability and porosity of effective reservoir.

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4.6 The effective thickness for Chang 6–Chang 9 oil layers

The Chang 6, Chang 8 and Chang 9 tight sandstones in the Zhenjing Block underwent a complex diagenetic evolution (Wang et al., 2005 and 2017a; Li et al., 2017a and 2019b; Shi et al., 2019, 2020a and 2020b; Liu et al., 2020b; Yang et al., 2020). However, in a single-layer thick reservoir, primary or secondary pores in the sand body are kept to a greater extent, and the physical properties are usually superior. After a comprehensive comparative analysis of wireline well logging, mud logging, and well testing analyses of the Chang 6, Chang 8, and Chang 9 oil layers, the cut-off of the thickness of single-layer effective reservoirs were found to vary among different layers, and the cut-off of the thickness of single-layer effective sandbodies are approximately 3.0 m, 3.0 m, and 2.0 m, respectively (Fig. 12).

Fig.12 Cross-plots showing single-layer thickness versus results of well testing of the Chang 6, Chang 8 and Chang 9 oil layers in the Zhenjing Block. Note: The dark dotted line represent the cutoff of single-layer thickness of effective reservoir.

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4.7 Planar distribution of effective tight sandstone reservoirs and its application to petroleum exploration

As mentioned above, the cut-off of the porosity of effective reservoirs in the Chang 8 oil layer is approximately 6.4% and 0.05 mD, and the corresponding cut-off of the thickness of single-layer effective sand body is approximately 3.0 m. Figures 13(a) and 13(b) show that the majority of commercial oil flow wells and oil flow wells are located in areas with>10% porosity and>3 m thickness of the single-layer sand body. In contrast, many of the drilling wells show dry layers and water layers all located in areas with<10% porosity and<3 m thickness of the single-layer sand body. As shown in Figs. 13(c)–11(d), the commercial oil flow wells, oil flow wells, and oil-water layers all plotted in the congruent areas of>6.4% porosity,>0.05 mD permeability and>3 m thickness of the single-layer sand body, the dry wells all plotted in the congruent areas of<6.4% porosity, <0.05 mD permeability and<3 m thickness of the single-layer sand body. These results note that the prospective targets are mainly distributed in long-strips in a NE-SW trend. Wherein the areas around wells HH44, ZT1 and HH103 are the major favorable areas.

Fig.13 (a) Planar distribution map of single-layer thickness>3 m, (b) isoline map of porosity, (c, d) superimposed map showing prospective targets of the Chang 8 oil layer.

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Determining favorable areas is essential to reserve calculation. In the process of its determination, an effective reservoir thickness is mostly taken as boundary basis. An energy-storage coefficient (ϕ∙h∙S_o, herein, ϕ is porosity, %; h is the thickness of single-layer, m; S_o: Oil saturation, %) was taken as the boundary basis to calculate reserves, and its planar distribution map was plotted by means of reservoir prediction (Zhang et al., 2018; Shi et al., 2019; Zhang et al., 2019; Chen et al., 2020). And accordingly, the lithological boundary of effective reservoirs was determined and the favorable areas were delineated. In contrast with the map of the energy-storage coefficient of the Chang 8 oil layer (Fig. 14), the majority of sandbodies in prospective targets were plotted in the area of the energy-storage coefficient>1.0.

Fig.14 Isoline map of the energy-storage coefficient of the Chang 8 oil layer.

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5 Conclusions

In the consideration of the characteristics of complex reservoir quality, non-Darcy flow, strong heterogeneity, and micro-pore throats of tight sandstone reservoirs, some approaches based on field operations and simulation experiments were preferred for comprehensive delineated the cutoffs of tight sandstone reservoirs. The preferred approaches are of profound significance for resource evaluations of tight oil reservoirs and the selection of exploration zones.

The physical property cutoffs of the effective reservoirs of the Chang 6, Chang 8, and Chang 9 oil layers are 7.9%, 6.4%, and 8.6%, respectively, and the cutoffs of the thickness of single-layer effective reservoirs are approximately 3.0 m, 3.0 m, and 2.0 m, respectively.

Using the preferred methods and combining with the cut-off of single-layer thickness, a superimposed map showing the planar distribution of the prospective targets was obtained. This map may delineate the effective boundary of prospective targets for petroleum exploration of tight sandstone reservoirs.

Acknowledgments

This study was supported by the National Natural Science Foundation of China (Grant Nos. 42072172 and 41772120), the Shandong Province Natural Science Fund for Distinguished Young Scholars (No. JQ201311), and the Graduate Scientific and Technological Innovation Project Financially Supported by Shandong University of Science and Technology (No. SDKDYC190313). We thank Shengli Oilfield Company of Sinopec for approving the publication. We also acknowledge the experts of Elsevier Webshop support for its linguistic assistance during the preparation of this manuscript. Three anonymous reviewers and Editorial Office were deeply acknowledged for their critical comments and helpful suggestions, which greatly improved the early version of this manuscript.

Electronic supplementary material

is available in the online version of this article at http://dx.doi.org/10.1007/s11707-020-0851-z and is accessible for authorized users.

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