Characteristics and formation mechanisms of tight oil: A case study of the Huahai Depression,Jiuquan Basin,Northwest China

Abstract

The exploration of tight oil reservoirs has achieved a big success, especially in the Huahai Depression, Jiuquan Basin, China, but the characteristics and formation mechanisms of the tight oil reservoir are unclear. In this paper, a series of analyses including thin section, scanning electron microscope, gas chromatography–mass spectrometry, isotope, and fluid inclusions were taken to study the tight reservoirs of the Xiagou Formation (K₁g) and Zhonggou Formation (K₁z) in the Huahai Depression. The results show that the main factors influencing the porosity and permeability of the tight reservoir are the compaction and two periods of carbonate cementation. The second type of carbonate cementation was related to the decarboxylation of organic acids in parts of the study area. The tight oil accumulation periods for different formations are confirmed, during 115–102 Ma in K₁g₁, 114–97 Ma in K₁g₂, and 103–85 Ma in K₁z₁, respectively. The tight oil migrations are executed for only several meters vertically but hundreds of meters even kilometers laterally. Two kinds of formation mechanisms exist in the study area. The main formation pattern is the “hydrocarbon accumulated after reservoir had tightened,” which has occurred in most of the study area. The other pattern, the “hydrocarbon accumulated during reservoir was tightening,” is found in several places of the study area.

Keywords

Tight oil reservoir oil-source correction accumulation period formation mechanism reservoir characteristics

Introduction

With the fast development of horizontal drilling and fracturing techniques in the last decades, unconventional reservoirs (i.e. tight shale, tight sandstone, and tight limestone) have drawn increasing attention. The global reserve of the tight oil is approximately 9230 × 10⁸ t, showing a tremendous exploration potential (Kuuskraa et al., 2013). The tight oil reservoir had been discovered in many basins in China, for instance, the Ordos Basin, Songliao Basin, Junggar Basin, and Jiuquan Basin, etc. (Jia et al., 2012). The geological resource of the tight oil in China ranges from 74 × 10⁸ to 80 × 10⁸ t (Jia et al., 2012; Zhao, 2012).

Many studies have been done about the geological characteristics of tight reservoirs. Most of the studies were focused on four aspects, including source rock, reservoir property, hydrocarbon accumulation mechanism, and enrichment conditions. The good source rocks of tight oil are generally characterized by the abundant organic matter, the moderate evolution degree, the intensive hydrocarbon generation, and the broad distribution (Zou et al., 2012). The tight reservoirs are generally fine-grained sediment and mainly constituted the siltstone and fine sandstone (Creaney et al., 1994; James, 2012; Sonnenberg and Pramudito, 2009; Webster, 1984; Yao et al., 2013). The reservoir pores are dominated by nanometer pores, while a certain amount of larger pores (ranging from millimeter to micrometer scale) are also developed (Camp, 2011; Kuhn et al., 2012; Ma et al., 2005; Nelson, 2009; Tang et al., 2015; Zou et al., 2012). The pore structure has intensive effects on the storage and seepage ability of tight oil reservoirs, which consequently result in poor porosity (less than 10%) and permeability (less than 0.1 × 10⁻³ µm) (Clarkson et al., 2012; Nabawy et al., 2009). The characteristics of low porosity, low permeability, and widely developed nanopores can be attributed to the complex diagenesis such as the compaction, cementation, dissolution, and recrystallization of clay minerals (Desbois et al., 2009; Islam, 2009; Larese et al., 1984; Nadeau, 2000; Pay et al., 2000). The hydrocarbon in tight oil reservoirs can be accumulated based on the broadly qualified source rocks that are in contact with the tight reservoirs (Jia et al., 2012; Johnston and Henderson, 2005; Kuhn et al., 2012; Smith and Bustin, 2000). The overpressure produced by the hydrocarbon generation overcomes the capillary resistance and further promotes the hydrocarbon into tight reservoir, which often manifests as the form of nonbuoyancy migration and non-Darcy flow (Merrikh and Mohamad, 2002; Spencer, 1987; Wang et al., 1999; Wu et al., 2007; Zeng et al., 2010). The migration styles are presented as the substantially primary migration and infrequently short-distance secondary migration (Nelson, 2009; Wang et al., 2011). The strata with overpressure, high intensity of hydrocarbon expulsion, high gas–oil ratio, and high fracture development degree are more beneficial for the enrichment of tight oil (Bohacs et al., 2013).

In the previous similar studies, due to the insufficient core samples and incomplete analysis, the accumulation process and formation mechanism (i.e. time and area) of tight oil in the Huahai Depression, Jiuquan Basin have not been thoroughly discussed, which inevitably restricts the ongoing exploration strategies. In this paper, SEM, thin sections, and isotope analysis of 224 samples in the K₁g and K₁z of the Lower Cretaceous, Huahai Depression, Jiuquan Basin are conducted to characterize the tight oil reservoir and clarify its controlling factors. Meanwhile, the main accumulation period of the tight oil is determined via fluid inclusion observations and homogenization temperature measurements. Moreover, the migration direction and distance of the tight oil are ascertained by the GC–MS analysis of the saturated hydrocarbons from both the source rocks and reservoirs. After that, the possible patterns of formation mechanism for tight oil and their corresponding distributions are carefully discussed.

Geological setting

The Huahai Depression is located in the northwest of the Jiuquan Basin, Northwest China (Figure 1(a)). It is a typical small half-graben rift depression in Mesozoic–Cenozoic with a total effective exploration area of about 500 km² (Men et al., 2005). The depression is bordered by the formation overlap separated from the North Mountains to the north, a high-angle normal fault separated from the Jiayuguan uplift to the east, the Aerjin deep fault separated from the Kuantaishan lower uplift to the south, and the formation overlap separated from Tianjinwei hilly mountains to the west (Figure 1(a) and (b)). The evolution of the Huahai Depression during the Mesozoic–Cenozoic can be divided into three stages: (1) the early Cretaceous extensional rift formed the lower Cretaceous with tremendous lacustrine sediments and shaped the main pattern of Huahai Depression; (2) the structure inversion, stratigraphic uplift, and denudation (with the denuded thickness of approximately 1000 m) during Late Cretaceous–Paleocene; (3) the compressional depression during the Paleogene–Quaternary time (Pan et al., 2006). Generally, the Huahai Depression is divided into five structural units, including the northern slope zone, the eastern fault belt, the southern fault/fold zone, the western slop belt, and the central sag belt (Figure 1(c)). The anticlines are not developed within the study area (Men et al., 2005).

Figure 1.

Geological setting of the Huahai Depression in the Jiuquan Basin. (a) Location of the Jiuquan Basin in China, (b) location of the Huahai Depression in the Jiuquan Basin, (c) tectonic units on the upper of K₁g₁ in the Huahai Depression, showing the sampling well locations, and (d) the lithology identified by logging of the well Ht7.

During the early Cretaceous, the progradational fan deltas in shore-shallow lacustrine deposited in the Huahai Depression and formed more than 3000 m sediments in the south of the central sag. Thus, the shallow-lacustrine sand-rich fan deltas extensively developed along the gentle slopes and the central part of the basin and formed the main tight oil reservoirs (Wang et al., 2008). The lower Cretaceous is subdivided into three formations, including the Chijinpu Formation (K₁c), the Xiagou Formation (K₁g) (composed by the lower Xiagou (K₁g₁) and upper Xiagou (K₁g₂)), and the Zhonggou Formation (K₁z) (composed by lower Zhonggou (K₁z₁) and upper Zhonggou (K₁z₂)) from the bottom to the top. Drilling data acquired since 1976 have recorded the oil/gas showing or gas logging anomalies in K₁g and K₁z. The wells D1, Ht7, and Ht9 were all drilled into tight oil reservoirs and yielded low tight oil productions. The strata of K₁g and K₁z are mainly composed of fine sandstone, siltstone, and mudstone (Figure 1(d)). The Ro of the source rock ranged from 0.7 to 1.3% and the kerogen type is II₁. The porosity of the reservoirs is less than 12% and the permeability is less than 0.1 mD.

Materials and methodology

Sixty-two samples were selected from the reservoirs in the well D1, well Ht9, well Ht7, and well Hs1 to conduct thin section analysis for the reservoir characterization, including petrography properties and diagenetic categories. The thin sections were partly stained with alizarin red and partly observed by using the cathodoluminescence microscope for the identification of carbonate minerals. Nineteen samples were examined with a field emission scanning electron microscope (Quanta 200F) at an accelerating voltage of 0.2–30 kV, thus the mineral materials, diagenetic characteristics, and pore types were identified, respectively. A total of 35 samples from different reservoirs were selected and made into polished thin sections preparing for fluid inclusions analysis. The fluid inclusion microthermometric analysis was carried out by using a Linkam THMS600 heating–freezing stage. One hundred percent phosphoric acid method (Guo et al., 2009) was used for oxygen and carbon isotope analysis of carbonate cements from 23 samples in this paper. The saturated hydrocarbons of 85 samples both from source rock extracts and reservoir bitumen in different wells at different depths were analyzed through the GC–MS (Agilent 7890-5975c GC–MS) to analyze the relationship between the source rock and reservoirs. The characteristics of sterane series were studied by monitoring m/z 217, while the characteristics of terpane series were studied by monitoring m/z 191.

Results and discussion

Diagenesis of tight oil reservoirs

The tight oil reservoirs in the Huahai Depression mainly belong to delta front facies and prodelta facies, while the single layer thickness of the reservoir is only a few meters. The reservoirs have significantly high feldspar and debris. The reservoirs generally exhibit poor porosity and permeability that mainly range from 4 to 10% and 0.01 to 0.1 mD, respectively. The pores in the reservoirs are dominated by nanopores (Fan et al., 2014). The reservoirs have experienced several kinds of diagenesis including compaction, cementation, and dissolution (Fan et al., 2014).

The compaction is a significant diagenetic event suffered by the sandstone reservoirs in K₁g and K₁z. The sediments in the reservoirs are medium–poorly sorted and subangular. With the increase of compaction intensity versus the burial depth, a large amount of plastic particles including mica, feldspar, slate, phyllite, and schist are prone to be compacted and deformed into the pseudo matrix, while the contact relationship between different minerals has been transformed from point contacting to line contacting and concave–convex contacting, thus the intergranular pore spaces became compressed and the porosity was heavily decreased (Figure 2(a)).

Figure 2.

Diagenesis of the tight oil reservoirs in the Huahai Depression. (a) The mica particles were bending by the compactions (well Ht7, 2987 m, K₁g₁), (b) calcite and dolomite cemented in intergranular pores (well Hs1, 2429.8 m, K₁g₂), (c) quartz overgrowth can be occasionally observed and the content of which is less than 1% (well D1, 2097.94 m, K₁g₂), and (d) feldspar dissolved was found locally (well Ht9, 2097.94 m, K₁g₂) (M—mica; D—iron dolomite; Q—quartz; I—illite; F—feldspar).

The cementation in the study area can be classified into two types including the authigenic clay mineral cementation and the carbonate cementation. The clay minerals are primarily formed by kaolinite, illite, chlorite, and illite/montmorillonite mixed layer minerals in the study area and they mainly appear in some limited intergranular pores. The clay minerals either decrease the pore space or divide the pore space into smaller parts, which also substantially reduce the permeability. A certain amount of carbonate cements (10–25% calcite and a few iron dolomite) were developed in the reservoirs of K₁g and K₁z (Figure 2(b)). The main carbonate cements developed within the intergranular pores and cracks in the form of sparry crystals, while little counterpart exist in the form of micrite by either replacing feldspar, detrital, and other mineral particles or mixing with the mud (Figure 2(b)). The cathodoluminescence shows that the carbonate cements are mainly formed in the two types (Figure 3). The first and second carbonate cements are, respectively, characterized as orange and yellow in the cathodoluminescence microscope, with the volume of 16 and 11% comparing with the total reservoir. Particularly, the second carbonate mineral cementation might lead to the reservoir becoming tight. The carbon and oxygen isotopic compositions of carbonate cements can provide valuable constraints on the sources, precipitation temperatures, and relative timing of cements in reservoir rocks (Macaulay et al., 2000). Generally, as the stratum temperature raises and the burial depth increases, the carbon and oxygen isotopic values of the carbonate cements decreased. The paleogeotemperature of the cements can be calculated using equation (1) (Shackleton, 1974). Therefore, the two types of carbonate were cemented separately at the paleogeotemperature of approximately 40–60 and 70–90°C, on the basis of the equation using the value of carbon and oxygen isotopes (Shackleton, 1974) (Figure 4). Combining with the burial history and thermal history simulated by one-dimensional basin modeling system, the two cementing periods of the carbonate minerals in the four target formations were predicted. And the corresponding two periods of time are determined at 132–126 and 121–116 Ma in K₁g₁, 125–121 and 113–110 Ma in K₁g₂, 120–110 and 108–77 Ma in K₁z₁, 118–112 and 105–86 Ma in K₁z₂, respectively (Figure 5). The origins of carbonate cements are related to the diagenesis, biogetic gas, or decarboxylation of organic acids. Both of the two periods of carbonate cements separately formed at the early and middle stage of diagenesis were strongly correlative with the early biogenic gas (Figure 6). In fact, only the carbonate cements on the upper of K₁g₂ and the base of K₁z₁ reservoirs were formed at the paleogeotemperature of 80–90°C and related to the decarboxylation of organic acid (Figure 6). In addition, few amount of quartz overgrowth can be occasionally observed (Figure 2(c))

t = 16.9 - 4.38 ((δ_{c} - δ_{w}) + 0.1 {(δ_{c} - δ_{w})}^{2}

(1)

where t is formation paleogeotemperature when the carbonate cements formatted, δ_c is the δ¹⁸_O value of the carbonate cements (PDB), and δ_w is the δ¹⁸_O value of the sedimentary water when the cements formation (SMOW standard).

Figure 3.

Cathodoluminescence features (CL) of the calcite in the tight oil reservoirs of the Huahai Depression. (a) Arkoses at 2145.66 m from K₁g₂ of well Hs1, two types of carbonate cements were developed in the reservoirs, the first type of carbonate cements shows orange in the CL image and accounts for 16% of the total reservoirs content, while the second type of carbonate cements shows orange in the CL image and accounts for 11% of the total reservoirs and (b) arkoses at 1380.3 m from K₁z₂ of well D1, two types of carbonate cements were developed in the reservoirs, the first type of carbonate cements shows orange in the CL image and accounts for 12% of the total reservoirs content, while the second type of carbonate cements shows yellow in the CL image and accounts for 3% of the total reservoirs).

Figure 4.

Formation times of carbonate cements from K₁g and K₁z in the Huahai Depression. The two types of carbonate were cemented at 50–60 and 70–80°C in K₁g₁, 40–50 and 60–90°C in K₁g₂, and 30–50 and 70–90°C in K₁z.

Figure 5.

Diagenetic evolution sequence and porosity evolution pattern of K₁g formation in the subsidence center of the Huahai Depression.

Figure 6.

The carbon and oxygen isotope distribution of carbonate cements from the tight oil reservoirs in the Huahai Depression. The carbonate cements are mainly biogenic gas-related carbonate cements with few organic acid-related carbonate cements.

The reservoirs in the study area have also been suffered from dissolution resulting in the formation of a small amount of intergranular dissolved pores and intragranular dissolved pores in the feldspar and detrital mineral grains (Figure 2(d)). However, due to the strong compaction, cementation, and high content of muddy matrix in the tight oil reservoirs, the porosity and permeability are fairly poor, which inhibited the acid fluid widely flowing into the reservoirs, and further made the dissolution developed limitedly. The diagenesis began to weaken and cease when the stratum began to uplift. Thus, the compaction and carbonate cementation are the most important factors for the decrease of porosity and permeability of the reservoirs in this area.

Maturity of tight oil

Fluid inclusions contain lots of information such as the thermal history, formation data, petroleum maturity, migration pathway, and accumulation period, etc. (Burley et al., 1989; Dubessy et al., 2001; McLimans, 1987; Stasiuk and Snowdon, 1997). The fluid inclusions from 35 reservoir samples within K₁g and K₁z in the study area are thoroughly observed to identify the maturity and accumulation period of tight oil. The hydrocarbon inclusions are generally not developed in the K₁g and K₁z, and only one period of low richness oil and gas inclusion distributed along diagenetic microcracks in quartz grain was detected.

Different fluorescent colors often indicate different components of the fluid captured by the hydrocarbon inclusions (Burruss, 1981), and thus further indicate the thermal evolution degree of hydrocarbons. In particular, with the increase of hydrocarbons maturity (from low to high), the fluorescent colors often vary gradually from red to orange, yellow, green, blue, and white (Goldstein, 1994; Munz, 2001; Stasiuk and Snowdon, 1997). Two types of hydrocarbon inclusions were developed in the K₁g₁, while only one type existed in the K₁g₂ and lower K₁z₁, and no hydrocarbon inclusions were detected in the K₁z₂. A small amount of transparent, colorless gas inclusions without fluorescence was developed in the lower K₁g₁, while the colorless and light oil inclusions with blue fluorescence were developed in the upper K₁g₁, which indicates that the maturity of the K₁g₁ oil is relatively high (Figure 7(a) and (b)). Very few hydrocarbon-bearing aqueous inclusions without fluorescence have been observed within the K₁g₂ reservoirs (Figure 7(c)). Only a few yellow-brown oil inclusions with yellow fluorescence in the K₁z₁ reservoirs indicate the oil maturity is low (Figure 7(d)). The diameter of the fluid inclusion is averagely less than 10 µm.

Figure 7.

Fluorescence photographs of the fluid inclusions of typical core samples in K₁g and K₁z reservoirs. (a) well D1, 2984 m, K₁g₁, gray gas inclusion, no fluorescence; (b) well Hs1, 2586 m, K₁g₁, light oil inclusions, blue fluorescence; (c) well D1, 2586 m, K₁g₂, gray hydrocarbon-bearing brine/aqueous inclusions; and (d) well D1, 1965 m, K₁z₁, brown hydrocarbon inclusions, yellow fluorescence.

Accumulation period of tight oil

One hundred and seventy-three homogenization temperatures of hydrocarbon-bearing brine inclusions and aqueous inclusions coexisting with the hydrocarbon inclusions were obtained from 10 samples in K₁g and six samples in K₁z. Based on the homogenization temperatures analysis, the paleogeothermal temperature of the reservoirs charged with oil should be mainly in the range of 100–115°C in the K₁g₁ and 80–90°C in the K₁g₂ and K₁z₁ (Figure 8(a) to (c)), respectively. Combining with the analysis of burial history, the main tight oil accumulation period is about 115–102 Ma for K₁g₁ reservoirs, 114–97 Ma for K₁g₂ reservoirs, and 103–85 Ma for K₁z₁ reservoirs, respectively (Figure 8(d)).

Figure 8.

Homogenization temperature of fluid inclusions and accumulation period of tight oil of the K₁g and K₁z reservoirs, the Huahai Depression. (a) Homogenization temperature of fluid inclusions of the K₁g₁, (b) homogenization temperature of fluid inclusions of the K₁g₂, (c) homogenization temperature of fluid inclusions of the K₁z₁, and (d) accumulation period of the K₁g and K₁z reservoirs.

Oil-source correlation of tight oil

The gas chromatographic analysis results of the saturate hydrocarbon from extractions of typical source rock samples and reservoir bitumen samples in the Huahai area are listed in Table 1, while the distribution of n-alkane is presented in Figure 9. The odd–even predominance (OEP) and carbon preference index values could reveal the relationship between the source rocks and hydrocarbons in reservoirs (Bray and Evans, 1961; Scalan and Smith, 1970). The OEP values of the source rock extracts and reservoir bitumen in the K₁g₂ and K₁z at the settlement center (well D1, Ht7, and Hs1) range from 1.13 to 1.8, indicating that both the hydrocarbons and source rocks have a comparably low maturity, whereas the counterpart in K₁g₁ from the same area varies from 1.0 to 1.2, indicating that the maturity is relatively high. Exceptionally, the OEP values for the K₁z₁, K₁g₂, and K₁g₁ of Ht9 well are lower than 1.2, which indicate a high maturity of the source rocks and reservoir bitumen. This might be produced by the abnormal high paleogeothermal gradient at that limited area close to well Ht9. The main C₂₁–C₂₃ carbon peak is distributed in K₁g₂, while the main C₁₅–C₂₁ carbon peak is located in K₁z₁ and K₁g₁. Eighty percent of ΣnC₂₁⁻/ΣnC₂₂⁺ numbers vary from 1 to 3. The lower main carbon peaks were dominantly distributed, suggesting that the organic matter was primarily derived from low-level aquatic organisms or plankton; while some samples have a bimodal carbon distribution, indicating that the organic matter comes from the input of both lower aquatic organisms or plankton and higher plants. The carbon number distributions of n-alkanes are relatively similar within a single formation at a well spot but apparently disparate for different formations (Figure 9(a)) or different wells (Figure 9(b)), which reveals that the tight oil had to be mainly migrated for a short distance and accumulated close to the source rocks.

Figure 9.

Distributions of n-alkanes in typical wells in K₁g and K₁z. (a) Samples from different formations in well D1 show the same characteristic in each formation and the K₁g₁, K₁g₂, and K₁z have different main carbon peak and (b) samples in same formations from different wells show different main carbon peak.

Table 1.

n-Alkanes and isoprenoids data in K₁g and K₁z, the Huahai Depression.

Well	Depth (m)	Formation	Lithology	CPI	OEP	ΣnC₂₁−/ΣnC₂₂₊	（nC₂₁+nC₂₂/(nC₂₈+nC₂₉)	Pr/nC₁₇	Ph/nC₁₈	Pr/Ph	Main carbon
D1	2338.5	K₁g₂	Source rock	1.53	1.30	0.59	2.21	0.62	0.39	1.40	C₂₅
D1	2340.95	K₁g₂	Reservoirs	1.45	1.61	2.87	2.20	0.69	0.53	1.64	C₁₅
D1	2584.4	K₁g₂	Source rock	1.18	1.19	1.80	4.06	0.30	0.29	1.14	C₂₁
D1	2587.8	K₁g₂	Reservoirs	1.23	0.98	2.03	2.40	0.50	0.61	0.86	C₁₅
D1	2684.8	K₁g₂	Source rock	1.21	1.14	0.78	1.89	0.19	0.20	0.96	C₂₃
D1	2984.5	K₁g₁	Reservoirs	1.12	1.02	1.57	1.74	0.34	0.34	1.06	C₁₇
D1	3148.5	K₁g₁	Reservoirs	1.11	1.04	1.78	1.99	0.27	0.36	0.86	C₁₅
D1	2099.5	K₁g₂	Source rock	1.29	1.21	0.57	1.55	0.35	0.62	0.62	C₂₅
D1	1483.8	K₁z₁	Source rock	1.85	1.40	1.34	2.53	0.91	4.24	0.22	C₂₃
Hs1	2158.2	K₁g₂	Source rock	1.24	1.11	1.20	2.26	0.33	0.19	1.88	C₂₃
Hs1	2145.9	K₁g₂	Source rock	1.22	1.07	1.44	3.21	0.32	0.30	1.20	C₁₇
Ht7	1578	K₁z₁	Reservoirs	1.33	1.13	1.15	2.81	0.39	0.35	1.13	C₂₁
Ht7	2988.6	K₁g₁	Source rock	0.84	1.19	1.03	1.08	0.94	3.03	0.42	C₁₇
Ht7	2986.6	K₁g₁	Source rock	1.23	1.07	1.42	3.02	0.15	0.17	0.91	C₂₁
Ht7	2922.5	K₁g₁	Source rock	1.23	1.04	1.55	3.57	0.19	0.20	0.99	C₁₇
Ht7	2987.6	K₁g₁	Reservoirs	1.28	1.05	1.42	2.74	0.38	0.48	0.79	C₁₇
Ht9	1578	K₁z₁	Reservoirs	1.33	1.13	1.15	2.81	0.39	0.35	1.13	C₂₁

CPI: carbon preference index; OEP: odd–even predominance.

The ratios of 20S/(20S + 20R) and ββ/(ββ + αα) for C₂₉ steranes can be employed to efficiently identify the thermal maturity of oil and source rock among a lot of biomarker parameters (Mackenzie et al., 1980; Peters and Moldowan, 1993; Seifert and Moldowanm, 1986). The ratios of 20S/(20S + 20R) and ββ/(ββ + αα) for C₂₉ steranes from typical samples of the reservoir bitumen and source rocks indicate that the hydrocarbons and source rocks were matured in K₁g₁ and K₁g₂, low mature to mature in K₁z₁, and immature in K₁z₂, respectively (Figure 10).

Figure 10.

Cross plots of crude oil maturity parameters: C₂₉ sterane ββ/(ββ + αα) of K₁g and K₁z in the Huahai Depression. The K₁g₁ and K₁g₂ were matured, the K₁z₁ was low mature to mature, and the K₁z₂ was immature.

The bitumen extracted from the K₁g₁ reservoirs are detected to be rich in pregnane, which is mainly formed by the cleavage of regular steranes under the sufficient evolution. The Ts/(Ts+Tm) ratios range from 0.49 to 0.69, indicating that the crude oil from K₁g₁ has a major high evolution degree and might come from the relatively matured source rocks. The GC–MS illustrates that the distributions of steranes and terpanes between the samples in reservoirs and that in nearby source rocks within the K₁g₁ are similar, especially the relative contents of regular steranes C₂₇, C₂₈, and C₂₉ (approximately 35, 18, and 46%, respectively) (Figure 11). Comparably, the value of gammacerane/C₃₀ hopane is much lower, varying from 0.04 to 0.14 in K₁g₁. The vertical distance between the two selected samples is higher than 60 m, which suggests that the generated hydrocarbon could be vertically migrated from several to tens of meters and thus formed the specific source–reservoir combination that the reservoir is developed under or within the source rock.

Figure 11.

Representative GC–MS of biomarkers identified in K₁g₁ source rock extract and reservoir bitumen. Source rock extract has the same biomarker characteristic with the reservoir bitumen sample.

The bitumen in the K₁g₂ reservoirs is also inspected to be abundant in pregnane, though the specific content is slightly lower than that of K₁g₁. Meanwhile, sorts of bitumen characteristics of K₁g₂ reservoirs indicate that hydrocarbons in this formation were from moderate matured source rock, for instance, the dispersal Pr/Ph ratios ranging from 0.3 to 1.88, the low gammacerane/C₃₀ hopane values varying from 0 to 0.16, and the moderate Ts/(Ts+Tm) ratios changing from 0.22 to 0.59, etc. In addition, the GC–MS display that the distributions of steranes and terpanes between the samples in reservoirs and that in adjacent source rocks within the K₁g₂ are similar, particularly the relative content of regular steranes C₂₇, C₂₈, and C₂₉ (approximately 31, 25, and 44%, respectively) (Figure 12). This very short vertical migration implies that the source–reservoir combination is prone to be the form that the reservoir is above the source rocks closely.

Figure 12.

Representative GC–MS of biomarkers identified in K₁g₂ source rock extract and reservoir bitumen. Source rock extract has the same biomarker characteristic with the reservoir bitumen sample.

Comparably, only a small amount of pregnane was detected in the bitumen samples of K₁z₁ reservoirs. Moreover, the corresponding properties including low Pr/Ph ratios (0.22–1.46), low gammacerane/C₃₀ hopane values (0–0.14), and low Ts/(Ts+Tm) values indicate that the oil was immature and derived from the source rock with a low maturity. Combining with the GC–MS, we found that the distributions of steranes and terpanes between the K₁z₂ reservoir bitumen sample at the well Ht9 and the extraction from the K₁g₂ source rock sample at the well Hs1 are similar, while the relative contents of regular steranes C₂₇, C₂₈, and C₂₉ in the two samples are approximately 44, 16, and 40%, respectively (Figure 13). This phenomenon indicates that the hydrocarbons might have been laterally migrated over hundreds of meters from lower source rocks into upper reservoirs.

Figure 13.

Representative GC–MS of biomarkers identified in K₁g₂ source rock extract and K₁z₁ reservoir bitumen. Source rock extract has the same biomarker characteristic with the reservoir bitumen sample.

The GC–MC analysis results display that the tight oil in the study area can not only be vertically but also laterally migrated. Normally, the tight oil in most reservoirs gave priority to the vertical migration, while that in the upper part of K₁g₂ and the lower part of K₁z₁ reservoirs might prefer to be laterally migrated. In particular, the vertical migration of the tight oil stretches only from several to tens of meters, while an obvious longer lateral migration varying from tens to hundreds of meters can be observed in the study area.

Formation pattern of tight oil

The conventional hydrocarbon can be both vertically and laterally migrated to a very long distance varying from several meters to hundreds of kilometers via various channels including faults, unconformities, and permeable sandstones, etc. In contrast, the tight oil reservoir is restricted in the nearby source rocks due to the formation mechanism.

Based on the reservoir properties, diagenesis, maturity, and oil-source correlation analysis, by comparing the accumulation period of tight oil with the cementation periods of the carbonate minerals in the study area, two types of formation pattern of tight oil were summarized. They are the pattern “hydrocarbon accumulated after reservoir had tightened” (Figure 14(a)) and the pattern “hydrocarbon accumulated during reservoir was tightening” (Figure 14(b)). The first type is mainly distributed in K₁g and K₁z₁ where the reservoir porosity and permeability had been reduced due to the integral effect of both the compaction and the cementation. As the example of K₁g shown in Figure 14(a), the hydrocarbons were vertically migrated from the source rocks into adjacent reservoirs at 115 Ma in the K₁g₁ and 114 Ma in the K₁g₂, respectively. As the limitation of low reservoir porosity and permeability, the migration distance was generally short (from several to tens of meters). On the other hand, the second type is mainly developed in the upper of K₁g₂ and the bottom of K₁z₁ (Figure 14(b)). In this case, when the hydrocarbons began to be migrated before 103 Ma (the paleogeotemperature of 80°C), the reservoir properties including the porosity and permeability are more acceptable since the second period of carbonate cementation in the upper of K₁g₂ and the bottom of K₁z₁ reservoirs had not been started yet. Thus, the hydrocarbons could be delivered along the permeable sandstones. Subsequently, the reservoir porosity and permeability were significantly reduced versus the processing of the second period of carbonate cementation caused by organic acid effects during 102–86 Ma (the paleogeotemperature of 80–90°C). In addition, the carbonate minerals derived from the deacidification of organic acids at the bottom of K₁z₁ also indirectly prove that the cementation of carbonate minerals is no earlier than the charging of the tight oil. After that time, the hydrocarbon migration and accumulation were substantially weakened due to the combined effect of both poor properties and power shortage. During the whole process, the hydrocarbons could be normally migrated from hundreds of meters to several kilometers (Figure 14(b)).

Figure 14.

Formation pattern of tight oil in the Huahai Depression. (a) The pattern “hydrocarbon accumulated after reservoir had tightened” and (b) the pattern “hydrocarbon accumulated during reservoir was tightening.”

It is crucial to define the hydrocarbon accumulation pattern, which could find its advantage in indicating the sweet spots distribution of tight oil reservoir especially in the early stage of exploration. For instance, for the pattern “hydrocarbon accumulated after reservoir had tightened,” the good tight oil reservoir distribution is prone to be dominated by the quality and distribution of source rock. Thus, the preferred exploration target should be focused on those places vertically close to good source rocks, which often have high TOC contents, moderate Ro values, and good organic matter types. On the other hand, if the hydrocarbon accumulation occurred during the reservoir was tightening, the potential exploration area might be widely distributed since the tight oil could be not only migrated vertically from several to tens of meters, but also laterally migrated several hundred meters.

Conclusions

The tight oil reservoirs in the Huahai Depression mainly belong to delta front facies and prodelta facies, while the average reservoir thickness is only a few meters. The feldspar and debris contents in the reservoirs are obviously high. The tight oil reservoir porosity and permeability are normally poor because of the integral effect of both the compaction and the carbonate cementation. The oil migration distance in the Huahai Depression varies in different directions. The tight oil can be not only vertically migrated from several to tens of meters, but also laterally migrated several hundred meters. The various source–reservoir combinations can be constructed, including the reservoir is developed above, below, or within the source rocks. Two kinds of accumulation pattern for the tight oil reservoir in the area are summarized. They are the pattern “hydrocarbon accumulated after reservoir has tightened” and the pattern “hydrocarbon accumulated during reservoir was tightening,” respectively.

Footnotes

Acknowledgements

We would like to acknowledge Yumen Oilfield Company for providing the drill cores used in this study, and we express our appreciation for their approval to publish the data.

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research, authorship, and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research, authorship, and/or publication of this article: This study was supported by the National Science and Technology Major Project (Grant No. 2017ZX05035-002), the 973 program of China Project (Grant No. 2014CB239105), the Science Foundation of China University of Petroleum, Beijing (Grant No. 2462017YJRC024), and the CNPC Science and Technology Major Project (Grant No. 2012E-3301).

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