Under the background of complicated diagenetic fluids, high-temperature pressure in superimposed basin, the pore-forming and pore-preserving effects of deep tight reservoirs are complex, and the formation mechanism of high-quality reservoirs has always been the core issue. With the discovery of oil and gas in ultradeep drilling in Tarim Basin, the most unconventional tight reservoir of Lower Cambrian Yuertus Formation in Tabei area began to receive attention. Based on the research of typical field outcrops in Tabei area, the lithofacies, reservoir space differences, and reservoir formation mechanism are systematically analyzed. (1) The stratum has undergone complex multistage diagenetic fluid transformation, and the rock types are diverse with great differences; siliceous rock and dolomite are the main rock types, often in thin-medium layered distribution. (2) After long-term deep burial transformation, siliceous rock and dolomite can still retain a large number of effective storage spaces; hydrothermal dissolution pores, organic acid dissolution pores, atmospheric freshwater dissolution pores, and intercrystalline pores are the main pore types, which provide main storage spaces. Multiscale pores are developed in siliceous rock and dolomite, with good connectivity and good pore structure. (3) The large-scale storage spaces mainly come from the effective maintenance of primary pores, organic matter, and hydrothermal dissolution. The siliceous minerals and dolomite have stable properties and strong resistance to compaction and can effectively maintain the early pores. (4) The large-scale reservoir space was formed in the early diagenetic stage; the pressure-solution and cementation are the two most important diagenetic processes for reducing storage spaces; however, under the pore-forming and pore-preserving effects of early silicification and dolomitization, various types of dissolution, and oil charging, the tight lithology can still maintain effective storage spaces. The related research has important theoretical and practical significance for studying the formation mechanism of tight reservoirs in deep ancient strata and predicting high-quality reservoirs.
With the continuous advancement of oil and gas exploration and development, the difficulty of oil and gas discovery in the middle and shallow layers is increasing, and the deep to ultradeep ancient reservoirs in superimposed basins have gradually become an important new field [1–3]. The basins where the ancient strata were located have been strongly transformed by tectonic activities, and the deep ancient strata often have the characteristics of deep burial, high temperature-high pressure, and multistage diagenesis transformation, which leads to unclear reservoir distribution rules [4–7]. More and more exploration practices have confirmed that deep ancient strata can also have good reservoirs and effective accumulation assemblages. Some ancient deep strata have successively discovered good oil and gas resources, such as the Sinian-Cambrian strata in the Sichuan Basin, the Sinian-Cambrianstrata in the Tarim Basin, and Ordovician strata in Ordos Basin [1–3, 8, 9]. Ancient oil and gas reservoirs of different scales have also been discovered in the Volga-Ural Basin in Russia, the McArthur Basin in Australia, the San Francisco Basin in Brazil, and the Rajasthan Basin in India [5, 10, 11]. These reservoirs include dolomite, limestone, but also shale, tight sandstone, siliceous rock, and other lithologies.
The Tarim Basin is composed of multiple tectonic systems and is rich in oil and gas resources. The Lower Cambrian Yuertus Formation has only been considered as a source rock for a long time, and the research on reservoir characteristics has not been carried out effectively. The source rocks in the Cambrian have an important influence on the formation of oil and gas. Most of the oil and gas reservoirs found at present are in the distribution range of Yuertus Formation or are distributed near this formation [9, 11]. Through field exploration and experimental analysis, previous research have determined that the Yuertus Formation contains high-quality marine source rocks with the highest organic carbon content found in China [9–11]. The Yuertus Formation is generally regarded as the main source rock in this area, and the research on its reservoir characteristics and controlling factors has not been carried out effectively.
The ultradeep wells in the northern Tarim Basin reveal that the Yuertus Formation has active oil and gas and shows potential for tight oil and gas development. Ultradeep wells including Luntan 1, Luntan 3, Tashen 5, etc., found that Yuertus Formation shows active oil and gas, with self-storage unconventional reservoir characteristics. The burial depth of the Yuertusi Formation in Well Luntan 1 reaches 8600 m-8700 m, and there are many gas logging abnormal enrichment layers. The maximum total hydrocarbon content is 14.59%, of which the C1 content can reach 10.83%. The mud logging is comprehensively interpreted as a high-quality gas layer [2, 6, 9–11]. The oil and gas performance of the Yuertus Formation in Well Luntan 3 is also good, and the depth of the coring section reaches 8500 meters (8516.74 m-8524.04 m). The core lithology is dominated by black gray mudstone and black siliceous rock, and the average TOC can reach 7.65% [2, 6, 11, 12]. Pore-fracture system is well developed. The Yuertus Formation in the northern Tarim Basin has important theoretical and practical significance for reservoir research.
Different from conventional oil and gas reservoirs, deep tight reservoirs usually develop a large number of micro-nano reservoir spaces, and the controlling factors are extremely complex [13–15]. The unconventional tight oil and gas reservoir space is generally micron-nanometer [13, 14]. Nanometer pore throat system is the essential feature of unconventional reservoir, which determines the special hydrocarbon accumulation mode and seepage mechanism [16–19]. The study of tight reservoirs should focus on the comprehensive study of multiscale reservoir space.
The reservoir space characteristics, controlling factors, and reservoir distribution rules of different rock types in deep ancient strata are quite different. The deep strata in superimposed basins are characterized by high temperature and high pressure and undergoing multistage diagenesis transformation [4, 10, 20–23]. In addition, the ancient strata also have the characteristics of diverse sedimentary systems, complex diagenesis, and diverse reservoir genesis [4, 10, 19, 21]. On the whole, the current understanding of ancient deep reservoirs is still in the initial stage, and related research is necessary to be carried out separately.
In summary, this study focuses on the Yuertus Formation in the northern Tarim Basin and comprehensively uses macro-micro, qualitative-quantitative reservoir petrological system analysis methods to analyze different rock types. The reservoir space characteristics and the controlling factors are systematically analyzed. This study has important theoretical and practical significance for revealing the types and controlling mechanisms of deep ancient tight reservoirs, especially for the prediction of unconventional reservoirs in the Lower Cambrian Yuertus Formation in the Tarim Basin.
2. Samples and Background
The Tarim Basin is located in the northwest of China. It is the largest oil and gas-bearing basin in China and is rich in oil and gas resources. The Lower Cambrian Yuertus Formation in the northern Tarim Basin is the main source rock of marine strata [2, 6, 9]. The Yuertus Formation has obvious thickness changes in this area, and the thickness is mostly between 8-35 m. The main lithofacies of this strata include siliceous rock, black shale, limestone, dolomite, and so on [2, 6, 11, 12] (Figure 1). The organic matter content of this group is very high, and the overall . In previous measurements of field profiles, the TOC can reach 7%-14%, and some even reach 22.39% [2, 6, 9, 11, 12]. In addition, it is widely distributed and relatively stable and was generally considered to be the main source rock.
Since the Cambrian, the Tarim Basin began to experience the transition from regional compression to extension, and the newly created regional tectonic framework plays an important role in the lithofacies and paleogeography of the Cambrian. In the northern Tarim Basin, a strong Keping movement occurred in the late Sinian, which caused the stratigraphic uplift and subsidence, resulting in stratigraphic unconformity between the Cambrian and Sinian [2, 4, 11, 12]. Due to the weathering and denudation in the late Sinian period, the higher protrusions on the ground were flattened, which made most of the basin in a flat and open environment when the Cambrian strata began to deposit, forming an open epicontinental shallow sea environment [2, 4, 11, 12]. The deposition of Yuertus Formation is influenced by the Early Cambrian sedimentary framework in this area (Figure 1).
Through field profile, thin section, electron probe secondary electron image, and other petrological observation methods, the petrological characteristics of macro-microstructure, mineral type, and pore type of different rock types are defined. Petrological evidences for diagenesis such as dissolution, cementation, hydrothermal transformation, compaction and pressure solution, and structural fracture in reservoir space are also provided. Cathodoluminescence was observed using a Nikon-LV100 polarizing microscope equipped with a CL8200 MK5-2 cathodoluminescence instrument, which was observed and photographed under the working conditions of 270 μA and 13 kV. Other microscope observations were also done at China University of Petroleum (East China).
Based on reservoir physical property tests, low field nuclear magnetic resonance (LF-NMR), and low temperature N2 adsorption/desorption (LTNA) test, the characteristics of multiscale pore structure of different rock type were carried out. The porosity test was completed in the Key Laboratory of Deep Oil and Gas of China University of Petroleum. LF-NMR analysis was performed in the Key Laboratory of Deep Oil and Gas, China University of Petroleum. Its analysis is based on the oil and gas industry standard “SY/T6490-2007”. According to the peak characteristics of spectrum, the pore characteristics of rock samples can be judged. The small values represent relatively small pore sizes. The area of the peak reflects the porosity of the reservoir space. The number of peaks reflects the type of pores.
Through the surface element scanning technology of electron probe, different minerals and diagenetic fluids are identified, and their pore characteristics and diagenesis are evaluated. Electron probe testing was completed in the Key Laboratory of Deep Oil and Gas, China University of Petroleum (East China), using an EPMA-1720 electron probe. Elemental scanning was performed on a max20 energy spectrometer, with a resolution of ≤ 127 and a peak-to-background ratio of ≥ 20000 : 1.
4. Results and Discussion
4.1. Pore Types in Different Petrology
The lithology of this formation is diverse, mainly including silicalite, limestone, dolomite, mixed rock, etc. (Figure 2, Table 1). The content of siliceous minerals ranges from 0.62% to 92.46%, with an average of 45.12%, which is relatively high. The calcite content ranges from 2.44% to 89.26%, with an average of 32.28%. The maximum content of dolomite is 41.48%, and the average is 10.75%. The average of clay mineral is 3.52%. In addition, there are some hydrothermal minerals, such as fluorapatite, barite, siderite, molybdenite, etc. These minerals indicate significant hydrothermal activity [2, 5, 7, 20–23]. The laminae are developed. The laminae are often interbedded with siliceous and carbonate layers, on which organic matter is mostly enriched (Figure 2).
There are various types of reservoir spaces, which can be mainly divided into fabric selective pores, nonfabric selective pores and cracks. The fabric selective pores include interparticle pores, intraparticle pores, and mold pores. The nonfabric selective pores mainly include dissolution pores and karst caves (Figure 2, Table 1).
Dissolution pores are mainly formed due to the erosion of some minerals by surrounding corrosive fluids. This type of pores can also be subdivided into interparticle dissolved pores and intraparticle dissolved pores, and the locations where dissolution occurs are different. Interparticle dissolved pores are formed by the dissolution of the edge of mineral particles, and their shape is affected by the shape of mineral particles, and most of them are irregular. Intraparticle dissolved pores are formed inside the mineral particles themselves after undergoing dissolution, and most of these pores are round (Figure 3, Table 1). There are many dissolution pores in this formation, which exist in siliceous rocks and carbonate rocks. Most of the intraparticle dissolved pores are round; the scale is relatively small, and the connectivity is relatively poor. Interparticle dissolved pores are often irregular, and the connectivity is related to the degree of dissolution (Figure 3, Table 1).
Interparticle pores are formed during the sedimentary burial period and diagenesis period due to the contact and support between mineral particles. Their shapes are generally square, triangular, polygonal, slit shaped, etc. (Figure 3, Table 1). Mineral particles can be the same or different. Due to the ancient age and deep burial depth of the Yuertus Formation, pores can be better preserved only in hard brittle minerals with strong compaction resistance. Strong compaction can compress and even destroy such pores. Such pores are often widely distributed and have strong connectivity, and they are also greatly affected by cementation, which will fill the pores and reduce porosity and permeability.
Cracks can greatly improve formation permeability and provide storage spaces for oil and gas, which is also an important factor affecting formation reservoir performance [21, 22] (Figure 3, Table 1). The formation of bedding cracks is mainly due to the existence of weak zones between the laminae. When subjected to external force, the rock tends to crack along the weak zones between layers, thereby forming bedding fractures. Bedding cracks can improve the lateral permeability of rock well, which is helpful for the lateral migration of oil and gas. In many samples, bedding cracks filled with black asphaltene and calcite can be seen. In addition, the formation of tectonic cracks is related to tectonic movement and is formed when rocks are subjected to tectonic stress during tectonic movement, and when the stress exceeds the elastic deformation range of the rock, the rock is broken and cracked [23, 24]. Its distribution and direction are related to the direction of stress. Both siliceous shale and limestone develop structural cracks, and the angle between the fracture and the bedding plane is between 70° and 90°, which greatly improves the vertical seepage capacity of the rock. The structural cracks are often filled with calcite, and there are also structural cracks that are not filled or filled with asphal (Figure 3, Table 1).
4.2. Differences in Multiscale Pore Structure
The reservoir space of the ancient tight strata is developed. Nuclear magnetic resonance (NMR) can perform nondestructive testing of lithology and can analyze its pore structure, pore size distribution, storage space, and other petrophysical characteristics [13–16]. The porosity of the sample can reach a maximum of 5.49% and an average of 2.81%. The pore structure of siliceous rocks is diverse and can be divided into three types (Figure 4(a)). Type I has large pores and good pore structure, and its peak range and area are large, indicating that siliceous rocks can well preserve pores. Type II is the left peak developed which represents that the large-scale pores are not developed while the small-scale pores are developed. Type III has developed left peaks and no right peaks, representing a pore structure in which small-scale pores are developed, but large-scale pores are not developed; the reservoirs with this type are relatively tight. In addition, it can also be seen from Figure 5(a) that siliceous rocks have developed pores with good connectivity and good pore structure (Figure 5(a)).
Dolomite rocks also show good pore structure characteristics. This rock type can develop better pore structure, and its peak range and peak area are large, indicating that dolomitization can play a good role in pore preservation in deep ancient strata (Figure 5(b)). At the same time, dolomite rocks also have the type of undeveloped pores. The peak range and area of this type are small, and the connectivity between the peaks is poor, indicating that dolomite can also be cemented to fill pores under certain conditions (Figure 5(b)).
The pore type of limestone is relatively simple, mainly micropores; the lithology is relatively tight, and the overall reservoir space is not developed (Figure 4(c)). The NMR spectrum of the limestone shows a single peak, mainly concentrated on the left side, with limited range and area of the peaks (Figure 4(c)). The characteristics of tight rock are related to the relatively active property of calcite, which is easy to cement and fill pores in deep ancient formations.
The above NMR curves show that the samples have the characteristics of multiscale spaces, and some samples have the characteristics of high left and low right peaks (Figure 4). When the pore size is less than 100 nm, the NMR signal increases significantly, and nanoscale pores provide a large amount of storage space (Figure 4).
A more precise analysis of the nanoscale reservoir space requires LTNA analysis [13–16] (Figure 6). LTNA analysis shows that the samples generally have developed nanoscale reservoir space. The maximum specific surface area of the samples can reach 1.02 m2/g; the average value can reach 0.52 m2/g. The maximum pore volume can reach 0.282 cm3/100 g, and the average value can reach 0.173 cm3/100 g (Figure 6). This analysis is consistent with the NMR results, showing relatively well-developed nanoscale reservoir space characteristics (Figures 4 and 6).
Although the isothermal adsorption curves of these samples are different in shape, they all show an inverse “S” type, and the adsorption and desorption curves do not coincide with a hysteresis loop (Figure 6). The LTNA adsorption isotherm is mainly type IV, and the adsorption curve can be roughly divided into three stages. In the low pressure stage when the relative pressure () is less than 0.4; the adsorption curve rises slowly and presents a slightly convex shape. Nitrogen molecules fill micropores or adsorb on the surface of shale samples. As the relative pressure increases to the medium pressure stage (), the adsorption curve is approximately linear, and the nitrogen molecules appear multimolecular layer adsorption. When the relative pressure reaches the high pressure section (), the nitrogen adsorption curve rises rapidly, showing a convex shape, and the adsorption and desorption curves of all samples show hysteresis loops (Figure 6). When the relative pressure is close to 1, the adsorption curve does not show a platform; there is still a trend of rapid increase, and there is no saturation phenomenon, indicating that the sample not only has nanoscale pores but also micron-scale pores, and its reservoir space development has multiscale characteristics (Figure 6). In addition, the nanoscale pore morphology is dominated by “wedge-shaped” slit pores, and there are very few “ink bottle-shaped” pores. Most of the measured curves of the samples are close to the H4 type, and a few are similar to the H2 type [14–17].
4.3. Formation Mechanism for Ancient Deep Reservoirs
4.3.1. Pore Preservation of Minerals
The siliceous minerals have stable properties, high hardness, and strong resistance to compaction and have an effective protective effect on the pores of deep ancient formations (Figure 7(a)). Comparing the average porosity of each rock type, it can be seen that siliceous shale has the highest porosity (the maximum porosity is 5.6%, and the average is 2.8%). Figure 7(a) shows that the overall porosity increases with the increase of siliceous content, indicating that siliceous is generally beneficial to the preservation of pores in deep formations. Microscopic petrological observations also show that the samples with high siliceous content retain more pores (Figure 2). Among the siliceous rocks, those containing some calcite have relatively low porosity (average 1.7%). Among the limestones, limestones with higher siliceous minerals generally have higher peaks, indicating that their pores are more developed. The average porosity of siliceous limestone reaches 2.4%, while the average porosity of limestone with low siliceous minerals is only 0.9%. In addition, the dolomite samples with high siliceous minerals also showed better pore morphology and porosity (Figure 4(b)). The above analysis shows that the protective effect of siliceous components on pores is very obvious.
In deep ancient strata, early dolomitization can effectively maintain pores, and moderate recrystallization of dolomite is also conducive to the formation of intercrystalline pores (Figure 7(b)). Dolomite has better compression resistance and brittleness, which can effectively preserve pores under deep burial conditions [22–24]. However, with the increase of dolomite, the change of porosity is not obvious (Figures 2, 7(c), and 8(a)). The phenomenon of dolomite minerals filling in the pores can also be seen. It can be seen that excessive dolomitization and dolomite cementation are not conducive to pore preservation (Figures 2 and 3).
4.3.2. Pore Reduction of Minerals
The time and degree of silicification will have different effects on pores. In the early stage of diagenesis, pores are relatively abundant, and silicification at this time can preserve the pores well. However, excessive silicification in the late stage of diagenesis can fill some pores and reduce the porosity (Figures 2, 3, and 9).
Calcite has active physical and chemical properties, and the dissolution-cementation process often occurs in ancient strata. In a relatively closed diagenetic system that is not connected by a fracture system, calcite can often be cemented to fill pores (Figures 2, 3, 8, and 9). Among all kinds of rocks, limestone has the lowest average porosity, only 0.9%. In addition, in other rock types, when the calcite content is high, the porosity is relatively low, and the pore structure is relatively poor. Calcite fills the pores and cracks, which can strongly reduce the reservoir space, making the lithology relatively tight (Figures 2, 3, and 9).
4.3.3. Pore Formation in Organic Matter Evolution
Organic matter in the formation is rich, and it has an important influence on the microscopic storage spaces, except for the hydrocarbon generation. The Yuertus Formation has high organic matter content and is the main source rock of the Cambrian subsalt in the Tarim Basin [7, 9, 11]. The TOC is between 3.7%-12.7%, and the average can reach 8.3%. After a long-term geological evolution process of organic matter, the value can reach 1.6%, indicating that the evolution process of organic matter hydrocarbon generation is sufficient [11, 12]. Organic acid dissolution is important constructive diagenesis in the deep ancient formations. Dissolution fractures-pores caused by organic acid are common, and they are often seen that the dissolved fractures-pores are connected to the residual bitumens (Figures 3 and 8). The acidic fluids generally select the previously existing weak point, such as interinner cracks. These acidic fluids can serve as precursors for hydrocarbon charging, which is conducive to hydrocarbon migration (Figures 3 and 8).
4.3.4. Transformation of Tectonic Hydrothermal Fluids
Hydrothermal fluid events in the hydrocarbon-bearing basins are unavoidable and even widely distributed [6, 8, 13]. After several stages of transformation in the Tarim Basin, hydrothermal fluids can be mantle derived, crust derived, and hydrocarbon derived or hot brines formed by heating thermal events such as infiltrated seawater and brines released from sediments. Hydrothermal fluids can come from deep crust with rich chemically active substances such as CO2, HCl, SO2, H2S, etc. and has a strong dissolution effect on the surrounding rocks [5, 9, 23, 24]. The porosity and pore structure of siliceous rock samples can be significantly better than other lithologic samples. For some samples with significantly higher porosity (porosity 4.02% and 5.08%), more hydrothermal minerals, such as apatite, barite, molybdenite, etc. can be seen than the rest of the samples (Figures 8 and 9). Most of the minerals are completely replaced by siliceous minerals, there are many hydrothermal dissolution pores, and siliceous minerals are attached to the surface of the pores. This reflects the strong erosion of hydrothermal activity resulting in a large number of pores and silicification (Figures 8 and 9).
The Lower Cambrian Yuertus Formation in the northern Tarim Basin has experienced multistage diagenetic fluid transformation, and the rock types are complex and diverse. The rock types can be mainly classified into siliceous rocks, dolomite and dolomitic rocks, limestone and calcite rocks, and mixed rocks. The siliceous rock is the main rock type, which is generally distributed in thin-medium layer
After long-term deep burial reconstruction, siliceous rock and dolomite can still retain a large number of effective storage spaces, and the reservoir space characteristics of different rock types are significantly different. Hydrothermal dissolution pores, organic acid dissolution pores, atmospheric fresh water dissolution pores, and interparticle pores are the main pore types, providing the main storage space. Multiscale pores are developed in siliceous rocks, with good connectivity and pore structure. Dolomite types also show good pore structure, but their porosity and distribution scale are smaller than those of siliceous rocks. The pore types of limestone are mainly micropores, and the storage space is not developed
The storage spaces mainly come from the effective preservation of primary pores, organic matter, and hydrothermal dissolution pores. The siliceous minerals and dolomite have stable properties and strong resistance to compaction, which can effectively maintain early pores in deep ancient formations. Dissolution pores caused by organic acid are common. Hydrothermal fluids with chemically active substances have strong dissolution effect on the surrounding rocks. The porosity and pore structure of siliceous rocks affected by hydrothermal fluids are significantly better than those of other types
In the long process of geohistorical evolution, the storage spaces have experienced multiple diagenetic events, and the quality of the reservoir depends on the dynamic balance results of porosity-increasing and porosity-reducing geological events. The large-scale storage spaces were formed in the early diagenetic stage. The compaction of limestone and the cementation of siliceous components are two important diagenetic events for the pore destruction under high temperature-pressure in deep burial environments. However, under the pore-forming and pore-preserving effects of early silicification and dolomitization, various types of dissolution, and oil and gas charging, the tight reservoir can still maintain effective storage spaces
The data used to support the findings of this study are included within the article. The data that support the findings of this study are available from the first author (Qilu Xu) upon reasonable request.
Conflicts of Interest
The authors declare no conflicts of interest.
Our study is supported by the National Natural Science Foundation of China (Grants 41902131, 41821002, and 42272154). The authors also sincerely appreciate the support from the State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development and SINOPEC Key Laboratory of Petroleum Accumulation Mechanisms (33550007-21-ZC0613-0067).