Abstract
Secondary hydrocarbon migration is an important aspect of oil-gas accumulation research. While previous studies have relied on geological and fluid geochemical characteristics to predict migration direction, these results are often limited by the number of samples. In recent years, basin simulation has emerged as a valuable tool in hydrocarbon migration research due to its extensive algorithms and adaptable modeling capabilities. It has obvious technical advantages especially for resource evaluation in areas with a lower exploration degree and scarce data. The deep oil and gas in the Cambrian petroleum system in the Tarim Basin is a deep hydrocarbon challenging area in China. There has been no breakthrough in exploration due to the large burial depth () and the long accumulation and transformation processes. Therefore, predicting the secondary migration of Cambrian oil and gas has become the key to solving this problem. In this study, first, the thermal evolution of the Lower Cambrian source rocks in the Tarim Basin was recovered, and the three thermal evolution models were developed. The secondary migration process of the Cambrian petroleum system was restored using the geologic model of the source rocks and paleotectonic evolution and the latest fluid potential information. By comparing the simulation results, four secondary migration models of the ultradeep oil-gas migration and accumulation were developed: multisource, multiphase, multidirectional accumulation; multisource, multiphase, single-directional accumulation; single-source, multiphase, multidirectional accumulation; and single-source, multiphase, single-directional accumulation. The fluid potential simulation results indicate that the Cambrian oil and gas have salient inheritance characteristics. The dominant migration channels in the uplift and slope are beneficial to oil-gas migration and accumulation, and the Katake uplift and the west Bachu uplift have multisource charging accumulation. The east Bachu uplift and the Tabei uplift are oil-gas accumulation zones that are beneficial to the lower petroleum system due to the continuous charging of a single petroleum system. This fluid potential simulation provides a new solution for studying the secondary migration of deep oil and gas. It provides an important reference for studying hydrocarbon accumulation in deep and ultradeep areas.
1. Introduction
The secondary migration of ultradeep oil-gas has always been an important part of research on oil-gas accumulation and is also a challenge in research on oil-gas accumulation [1, 2]. Most scholars have judged the direction of secondary oil and gas migration based on structural features, and their results are generally consistent with the exploration status, which is often affirmed in practice [3, 4]. However, the shortcoming of this method is that it can only provide the qualitative trend and cannot yield the effective path of the fluid migration and historical evolution. Some scholars have also made good progress in determining the direction of secondary oil and gas migration based on the properties of fluids [5, 6], but application of this method is limited by a lack of sufficient samples and high costs. The fluid potential has been recognized as a quantitative method for studying secondary hydrocarbon migration in petroleum geology theory [7], but few results have been reported in the literature. The main reason for this is that calculating the fluid potential has high geological model requirements, which requires matching the hydrocarbon system elements such as the source rock, reservoir, and trap, and it is difficult to meet these requirements in actual study. The latest basin modeling technique quantifies the source rocks and the secondary oil-gas migration process through dynamic, hydromechanical, and physical means [8–11] and has attracted increasing attention in the field of oil-gas exploration [12–14], which can provide a better reference for studying ultradeep oil-gas accumulation.
With an average burial depth of >600 m, the Cambrian system in the Tarim Basin represents one of the difficult areas of ultradeep oil-gas exploration in marine facies in China [15–18]. Wells TS1, ZS1, and LT 1 revealed the wide distribution of the oil-gas resources in the ultradeep system. The large burial depth of the Cambrian system in the Tarim Basin and the long adjustment time in the late construction and transformation phases have resulted in an extremely low degree of exploration. As a result, the secondary oil-gas migration and accumulation processes of the petroleum system remain unclear [19, 20], which limits the evaluation of the ultradeep zone and exploratory deployment. Therefore, in this study, a new method combining effective source rock data with paleotectonic evolution was developed to simulate the fluid potential of the Cambrian petroleum system, and the secondary hydrocarbon migration was reconstructed. The application of fluid potential analysis for hydrocarbon resource evaluation provides a new reference for studying deep hydrocarbon accumulation.
2. Geologic Background
2.1. Regional Position
The Tarim Basin is located in northwestern China and has a total area of 530,000 km2. The Tarim Basin contains several structural zones (four depressions and three uplifts) due to multiple stages of tectonic movement during the Caledonian, Hercynian, and Himalayan orogenies [21, 22] (Figure 1(a)). The tectonic evolution consisted of six stages [22], including two intense periods of magmatic activity and volcanic eruptions in the Early Caledonian and Late Hercynian [23].
(a)
(b)
The early tectonostratigraphic evolution of the Tarim Basin involved a change from continental rift or aulacogen environment (from the Sinian to the Early Cambrian), which was related to the breakup of Rodinia, to a passive continental margin and intracratonic depression (Cambrian to Early-Middle Ordovician), and the Cambrian strata were mostly deposited on a carbonate platform in a cratonic setting [24].
A large-scale transgression took place during the Early Cambrian, resulting in the deposition of deep-water, dark mudstones at the base of the Cambrian, which are one of the main hydrocarbon source rock intervals in the basin [24]. In the late Early Cambrian, the sea level dropped significantly, and under the dry and hot climate, a shallow, evaporative basin covering an area of ~130,000 km2 enabled the precipitation of gypsum and halite [25]. This evaporative carbonate platform setting persisted throughout the Middle Cambrian, resulting in the formation of thick gypsum and salt layers intercalated with dolostone [25]. In the Late Cambrian, the restricted basin gave way to an open carbonate platform on which thickly bedded dolostone accumulated.
The Cambrian succession consisted of six formations overlying Precambrian metamorphic basement. From bottom to top, the strata include the Lower Cambrian Yuertusi, Xiaoerbulake, and Wusonger formations; the Middle Cambrian Shayilike and Awatage formations; and the Upper Cambrian Qiulitage Formation (Figure 1(b)). Lithologically, the Yuertusi Formation is comprised of dark, organic-rich, siliceous muddy shales interbedded with phosphorites, thinly bedded dolostones, limestones, and diatomites, which were deposited in slope and basin settings [26, 27]. The Xiaoerbulake Formation consists of gray to dark gray micritic and fine-grained dolostones at the base and algal and sandy dolostones at the top, which were deposited in platform margin and interplatform reef and inner shoal settings [27]. The Wusonger Formation is dominated by gray muddy dolostones and gypsum [26, 27]. The Middle Cambrian Shayilike Formation is composed of gray limestones and dolomitic limestones, which were deposited on a platform with a high evaporation rate [26, 27]. The Awatage Formation mainly comprises gray gypsum, dolomitic gypsum, and subordinate micrite [25, 26]. The Upper Cambrian Qiulitage Formation mainly consists of gray micritic and sandy dolostones [27, 28].
2.2. Cambrian Petroleum System
The successful implementation of deep exploratory wells (Figure 1) has demonstrated that high-quality source rocks, mainly from the Cambrian system to the Lower Cambrian, were widely developed in the interplatform basin [29–31]. In addition, analysis of wells ST1, TS1, BT5, YQ6, and ZS1 revealed that many cracks and holes were developed in the Lower Cambrian Xiaorbulak Formation, the Middle Cambrian Shayilik Formation, and the Upper Cambrian Lower Qiulitage Group [32]. Based on the gypsolyte in the thick-layer zone developed in the Middle Cambrian [25], the upper, middle, and lower petroleum systems in the Cambrian system were formed in better than good Cambrian reservoir strata (Figure 1). Due to the limited distribution of the Middle Cambrian system in the Tarim basin, this study focused on the upper and lower petroleum systems.
2.3. Current Exploration Situation
There are a total of 18 wells drilled in the Cambrian strata in the Tarim Basin, and most of these drilling and logging wells have revealed indications of oil-gas in the Cambrian system. Bitumen was encountered in wells ST1 and TS1, and light oil was encountered in wells ZS1 and ZS5. Wells T 1, BT5, MB1, K2, XH 2, TS1, TS2, HT1, YQ6, ST1, WL1, LT 1, PSB2, TC1, YB1, XH1, AD1, TD1, TD2, and MC1 were mainly selected for analysis in this study.
3. Methods and Data
3.1. Source Rock Analysis
The organic matter abundance is an important parameter for evaluating source rocks, and it represents the potential for hydrocarbon expulsion and generation. Some scholars have measured the organic matter abundances of the source rocks in the Lower Cambrian in the Tabei uplift and have reported contents of 7–14% and up to 22.39% in local regions (Table 1) [19, 33]. The exploration activities have demonstrated that the Cambrian oil and gas in the Tarim Basin mainly came from the Lower Cambrian source rocks [20, 29, 34], but few studies have been conducted on the thermal evolution characteristics of the source rocks in the interplatform basin. Regional studies have revealed that a set of shale deposits was developed on the deep-water shelf and slope in the Lower Cambrian [35]. The cores and field profiles indicate that the organic carbon content varies from 13.89% to 22.39%, and the hydrogen index (HI) varies from 51 mg/g to 1055 mg/g.
3.2. Basin Modeling
The thermal history and oil-gas migration in the Cambrian System in the Tarim Basin were simulated using the Schlumberger PetroMod program, in which a 1D module was used for the thermal history modeling, and a 3D flow path module was used for the oil-gas migration modeling in PetroCharge program.
3.3. Modeling Methods
3.3.1. Thermal History Modeling
The purpose of modeling the thermal history was to predict the maturity and scope of the source rock in each geological period. The vitrinite reflectance is the most typical and common geochemical index of thermal evolution [36, 37]. There are many methods for recovering the thermal history, e.g., the thermometer method, the Karweil graphical method, and the Hood method. According to previous studies, the Easy%Ro chemical kinetics model (Equation (1)) is more accurate for source rocks with a middle to high degree of thermal evolution. where is the vitrinite reflectance (%) and is the degree of chemical reaction at the th burial point at the bottom stratum of the well, with a value range of 0–0.85.
3.3.2. Fluid Potential Modeling
The fluid potential concept of Hubbert has been widely quoted [4, 11] and has become a fundamental theory for studying oil-gas migration. The streamline method was used for the fluid potential modeling conducted based on Darcy’s law. The flow velocity of the hydrocarbon is as follows: where is the permeability tensor; is the relative permeability; is the viscosity, and is the overpressure gradient. The buoyant force is the driving force and satisfies , where and are the densities of water and oil, and m/s2. Generally, the streamline method reveals the migration and accumulation trends from the source rocks to the traps. The streamline length represents the distance of the fluid migration and accumulation. The streamline accumulation indicates that the oil and gas are trapped along the dominant migration channel. In this fluid potential simulation, the Lower Cambrian source rocks were characterized by the bottom interface of source rocks T90. The trap was characterized by the structural morphology of the reservoir’stop surface, the Lower Cambrian petroleum system trap was selected as the reservoir’s top interface T84, and the upper interface was T80.
3.4. Selection of Single Wells for Modeling
In this study, nine exploratory wells in different tectonic units in the study area were selected for hydrocarbon generation and expulsion history modeling. Well AD2 in the Awati depression; well MS1 in the west Manjar depression; wells XH1, TS2, and YQ6 in the Tabei uplift; well WL1 in the Kongquehe uplift; well MC1 in the Manjar depression; well TC1 in the Tanggubasi depression; and well YB1 in the Maigaiti slope were selected for thermal evolution modeling.
3.5. Formation Framework and Lithological Parameters
Based on the formation sequence of a single well in the study area [38], the current formation interface was focused on, and a formation framework at different geological times was constructed based on the geologic chronology. Based on the analysis of the single-well data, the selected single wells were commonly drilled below the Ordovician strata, and for the wells that did not reach the Cambrian system, the formations were estimated based on seismic data for the reference region (Table 2). The interpreted relevant seismic data were mainly obtained from the Sinopec Exploration and Development Research Institute.
The key to properly calibrating the formation compaction and objectively recovering the burial history of the deposits is to correctly select the lithological parameters of the formation. Based on the drilling data and logging data for single wells, the lithology of each formation and its percentage content was calculated. The mixed lithology was mixed from the standard lithology using a certain percentage based on the calculation results. The thermal conductivity and compaction coefficient were set as the default values of the model.
3.6. Recovery of Erosion Thickness
The erosion thickness is a critical factor in recovering the burial history. Multiple uplift events occurred in the Tarim Basin, resulting in 9 unconformities (Figure 1(b)): the Cretaceous (T40), Triassic (T50), Carboniferous (T57), Upper Devonian (T60), Silurian (T70), Upper Ordovician (T72), Middle Ordovician (T74), Upper Cambrian (T81), and Lower Cambrian (T90) unconformities. The erosion data are partially from the Northwest Oilfield Company Research Institute Foundation Institute, and they mainly include the erosion thicknesses of the Ordovician, Silurian, Devonian, Carboniferous, Permian, Triassic, Jurassic, and Cretaceous formations. According to the data statistics, the amounts of erosion of the Ordovician, Silurian, and Permian formations were large (Table 3).
3.7. Boundary Conditions
3.7.1. Paleo-Geotemperature
The surface temperature includes the current temperature and the paleo-geotemperature. Although there is a difference in the current surface temperature in the Tarim Basin, the difference is small, and the surface temperature is often taken as 18°C [15]. The background value of the paleo-geotemperature is usually set using a customized Wygrala (1989) model in PetroMod. The Tarim Basin is located in the Eastern Asian Plate (39°N) in the Northern Hemisphere. Owing to the variations in the geologic age, the paleo-geotemperature usually varies from 16°C to 30°C (Figure 2).
3.7.2. Paleowater Depth
Paleowater depth analysis is important and significant for reconstructing the paleoenvironment, basin structure, and evolution [39]. In this study, the paleowater depths in the different regions were mainly calibrated based on the sedimentary history of the Tarim Basin and the uplift trend of its elevation (Table 4).
3.7.3. Paleoheat Flow
The Paleozoic heat flow is the product of the geothermal gradient and the thermal conductivity of the rocks. Different tectonic evolution pathways result in different Paleozoic heat backgrounds [37]. The thermal conductivities of the main lithologies of the different strata were obtained based on a field core thermal conductivity test (Table 5). The geothermal gradient in the platform basin was found to be between 3.37 and 1.9°C/100 m via drilling temperature measurements in the reference area (Table 6), and it has exhibited a decreasing trend since the Cambrian. The results are as follows: 34–44 mW/m2 in the Cambrian–Ordovician, 40–56 mW/m2 in the Silurian–Devonian, 41–78 mW/m2 in the Carboniferous–Permian, 39–76 mW/m2 in the Triassic–Cretaceous, 35–65 mW/m2 in the Cenozoic, and 34–55 mW/m2 at present. The evolution of the heat flow was as follows: low in the Early Paleozoic, high from the Late Paleozoic to the Mesozoic, and low at present, which is consistent with the results of previous studies [40, 41].
3.7.4. Paleostructural Restoration
The evolution of the ancient structure has a great influence on secondary hydrocarbon migration and accumulation. The stratum stripping method uses the compaction curve to restore the paleothickness of the stratum [42, 43]. In the calculation, the paleoelevation depth (HSL) of the corresponding structural surface is usually considered to be the sum of the tectonic depth (-Hd) in the historical period relative to the historic sea level and the denudation thickness (Hb) before the historical period [44]. Therefore, the ancient elevation depth (HSL) at any point in the basin can be expressed as follows:
In this study, the ancient structures of the Lower Cambrian interface (T84) and the Upper Cambrian interface (T80) were recovered.
3.8. Fluid Potential
The fluid potential is an important reference parameter for studying the direction and channel of secondary oil-gas migration [11, 45–47]. In this study, the latest Schlumberger PetroCharge model was combined with the paleostructure and maturity of the source rocks to calculate the paleofluid potential and to explore the fluid charging and migration in both the Upper and Lower Cambrian petroleum systems in the Tarim Basin to determine the migration and accumulation characteristics of the ultradeep oil-gas system in the basin.
4. Results
4.1. Thermal Evolution of Lower Cambrian Source Rocks
4.1.1. Model of Thermal Evolution
The purpose of thermal history modeling is to reconstruct the thermal history of the sedimentary formation in the basin, which is an important basis for analyzing the temperature and maturity of the hydrocarbon source rock in each geological period [37, 40]. In this study, nine exploratory wells in five of the major tectonic units in the interplatform basin were selected as representative of the geological background. These wells were used to recover the partial Cambrian thickness values and to create a model of the thermal evolution of a single well constrained by the vitrinite reflectance (Table 1) in the Paleozoic based on the related paleoheat flow values for the reference regions. According to the model of the thermal evolution of the basin, the Lower Cambrian source rocks in the interplatform basin experienced different thermal evolutions (Figure 3), and the following three thermal evolution models were developed. (1) The continuous hydrocarbon generation model is the representative wells that include wells AD1, TC1, and AM1. Owing to the influence of the continuous settling, the thermal evolution of the source rocks was characterized by a continuous increase in temperature. The vitrinite reflectance varies from 1.3% to 4%. Overall, it is in the mature stage and is mainly developed in the basin depression. (2) The continued hydrocarbon generation model is the representative wells that include wells TS2 and PSB2. The hydrocarbon generation process occurred during stages of temperature increase. The vitrinite reflectance varies from 0.7% to 4%. Overall, it is in the mature to overmature stage and is mainly developed in the slope. (3) The fast hydrocarbon generation model is the representative wells that include wells WL1 and YQ6. The thermal evolution of the source rocks began from the Cambrian to the Silurian–Devonian and then entered a lag phase, undergoing an early rapid increase in temperature and a later lag in the temperature increase. The vitrinite reflectance varies from 0.7% to 1.3%. Overall, it is in the mature to over-mature phase and mostly occurs in the mountain front. The representative well of the late fast thermal evolution model is well XH1. The thermal evolution rate increased rapidly after the Miocene, i.e., the late fast thermal evolution model.
4.1.2. Hydrocarbon Generation Model
In this study, the hydrocarbon generation and expulsion histories of nine exploratory wells in the different tectonic zones in the study area were reconstructed (Figure 4) based on the hydrocarbon generation history of the Lower Cambrian source rocks in the different tectonic zones. Three hydrocarbon generation and expulsion models were developed for the Lower Cambrian strata in the interplatform basin. (1) The continuous hydrocarbon generation model is the representative wells that include wells AD1, TC1, and AM1. The hydrocarbon generation began in the Late Ordovician. The peak period of liquid hydrocarbon generation was from the Devonian to the Carboniferous, and the peak period of gas generation occurred in the Early Permian. The hydrocarbon generation process was continuous. (2) The continued hydrocarbon generation model: the representative wells include wells TS2 and PSB2. The hydrocarbon generation began in the Late Ordovician. The peak period of hydrocarbon generation occurred in the Late Carboniferous, the peak period of liquid hydrocarbon generation occurred in the Permian, and the peak period of gaseous hydrocarbon generation occurred in the Triassic. The hydrocarbon generation occurred in stages. (3) The fast hydrocarbon generation model is the representative wells that include wells WL1 and YQ6. The thermal evolution of the source rocks occurred from the Cambrian to the Silurian–Devonian and then entered a lag phase. Owing to the relatively low degree of thermal evolution, this was the early fast hydrocarbon generation model. For example, in well XH1, a rapid increase in the degree of thermal evolution occurred after the Miocene, and the peak of oil and gas generation was reached, i.e., the late fast hydrocarbon generation model. Overall, the Lower Cambrian source rocks in the Tarim Basin were characterized by early oil generation and late gas generation, and the hydrocarbon generation history was different in the different regions.
4.2. Oil-Gas Migration and Accumulation Trends of the Petroleum System
Based on the description of the current formation structure in the basin, the paleostructure of T90 in the Lower Cambrian during four critical period (e.g., the Middle Caledonian, Early Hercynian, Late Hercynian, and Late Himalayan) was recovered (Figure 5). It can be seen from Figure 6 that in the Lower Cambrian, the Tarim Basin experienced long-term tectonic subsidence, but there were obvious differences under the influence of the structure of the basin’s base and tectonic compression. Among them, the Manjar depression and Tanggubasi depression have been depressions for a long time, and their scope has been expanding. The Awati depression began to rapidly settle in the Late Hercynian. The Bachu area consists of a monocline that is high in west and low in east and developed between the Caledonian and Early Hercynian. After the Late Hercynian, it was compressed by the NE trending structure, and the structure reversed, producing an uplift and depression pattern that was low west and high east. The above reconstruction of the tectonic evolution is consistent with the results of a previous study [48].
(a) Middle Caledonian
(b) Late Caledonian
(c) Late Hercynian
(d) Late Himalayan
(a) Middle Caledonian
(b) Late Caledonian
(c) Late Hercynian
(d) Late Himalayan
Based on the evolutionary characteristics of the paleostructure, the characteristics of the thermal evolution of the source rocks in the Lower Cambrian system during four critical period (i.e., Middle Caledonian, Late Caledonian to Early Hercynian, Late Hercynian, and Late Himalaya) were reconstructed using the PetroMod software, and the results are consistent with the thermal evolutions of the single wells (Figure 6).
According to the thermal evolution of the Lower Cambrian source rocks (Figure 7), the Lower Cambrian source rocks in the Manjar depression, Tanggubasi depression, and Awati depression in the interplatform basin entered the mature stage as a whole in the Middle Caledonian (Figure 6(a)) and provided the material foundation for the development of the paleo oil reservoir in the Caledonian. From the Late Caledonian to Early Hercynian, the Lower Cambrian strata underwent rapid thermal evolution due to continuous sedimentation, and the source rocks in the interplatform basin entered the mature-highly mature stage as a whole, providing oil-gas sources for the oil-gas reservoir in the Hercynian (Figure 6(b)). In the Late Hercynian, the Lower Cambrian source rocks in the interplatform basin entered the mature to overmature stage, and the thermal evolution of the source rocks succeeded the characteristics in the Early Hercynian, during which the source rocks in the Maigaiti slope entered the mature stage as a whole (Figure 6(c)). In the Himalayan, the Lower Cambrian source rocks in the interplatform basin entered the highly maturity stage and had already been in the overmature stage in the depression (Figure 6(d)), resulting in late gas migration in the interplatform basin.
(a) Middle Caledonian
(b) Late Caledonian
(c) Late Hercynian
(d) Himalayan
Overall, the thermal evolution of the Lower Cambrian source rocks in the interplatform basin was greatly different in the different regions. That is, the degree of thermal evolution was the highest in the Manjar depression and lagged in the Maigaiti slope and southwestern depression in the Tarim Basin. The overall trend was early in the east and late in the west. Within the same tectonic unit, the vitrinite reflectance of the hydrocarbon source rocks varied, e.g., in the Shuntuoguole low uplift and the Maigaiti slope, which is an important reason for the existence of multiphase oil-gas reservoirs in the interplatform basin. The northern Tarim slope, Shuntuoguole low uplift, and Maigaiti slope had an overall source rock maturity of less than 2%, i.e., the high-maturity stage. Owing to their large hydrocarbon generation potential, they are promising targets for deep oil-gas exploration.
4.3. Oil-Gas Accumulation in the Lower Petroleum System
In this study, the thermal evolution characteristics of the source rocks, reservoir physical properties, and trap evolution characteristics were used to reconstruct the fluid migration in the different periods in the oil-gas systems (Figures 7 and 8). In the Tarim Basin, the Lower Cambrian petroleum system consists of the Lower Cambrian source rocks, the Xiaorbulak Formation, and the Middle Cambrian gypsolyte, and it is widely distributed in the basin. Based on the thermal evolution of the Lower Cambrian source rocks, the oil-gas migration and accumulation trends of the Xiaorbulak Formation were simulated during four critical phases (Figure 7).
(a) Hercynian
(b) Himalayan
It can be seen from the oil-gas migration processes of the petroleum system that the oil-gas charging began in the Middle Caledonian (Figure 7(a)), and the Hercynian was the liquid hydrocarbon accumulation period (Figures 7(b) and 7(c)). The gaseous hydrocarbons mainly accumulated in the Himalayan (Figure 7(d)). The hydrocarbon reservoir formation was characterized by early oil and late gas accumulation. According to the analysis of the four petroleum systems, the streamline was long in the Early Caledonian and Hercynian and was characterized by a distant source and long-distance migration. As the maturity of the source rocks increased, the streamline began to widen and shorten, and there was a distant source charging between the source and traps. The streamline accumulation occurred in the paleo uplifts. The Katake uplift is characterized by multisource charging accumulation due to the influence of the Manjar, Awati, and Tanggubasi petroleum systems and is the most favorable oil-gas accumulation zone in the lower petroleum system in the interplatform basin. Owing to the combined charging from the petroleum systems in the Maigaiti slope and Tanggubasi depression, the west Bachu uplift is a favorable oil-gas accumulation zone in the lower petroleum system. Owing to the continuous charging of the single petroleum system, the east Bachu uplift and the Tabei uplift are favorable oil-gas accumulation zones in the lower petroleum system. In addition, the area surrounding the dominant migration channel is also a favorable oil-gas accumulation zone. Based on the analysis of the oil-gas migration and accumulation trends in the Himalayan (Figure 7(d)), the Manjar petroleum system, Awati petroleum system, and Maigaiti slope petroleum system have developed 11, five, and eight dominant migration channels, respectively, which are favorable target areas for evaluating the gas reservoir in the lower petroleum system.
According to the oil-gas indications in the drilling wells throughout the entire basin, good oil-gas indications have been observed in the Xiaorbulak Formation in the Bachu and Tabei areas [49, 50]. Bitumen has been found in the Xiaorbulak Formation in well ST1 in east Bachu, and a gas production rate of m3/d has been obtained from the Xiaorbulak Formation in well ZS1. A high yield of light crude oil has been obtained from well LT 1 in the Xiaorbulak Formation in the northern part of the Tarim Basin [30]. In addition, good oil-gas indications have been observed in the lower petroleum system in wells TC1, K 2, and H 4, which demonstrates the large oil-gas accumulation potential of the Lower Cambrian Xiaorbulak Formation [51]. The results of the streamline modeling are consistent with the above oil-gas indications and the hydrocarbon generation and expulsion histories of the single wells, indicating that the oil-gas accumulation modeling has a good reference value.
4.4. Oil-Gas Accumulation in the Upper Petroleum System
The Upper Cambrian petroleum system consists of the Lower Cambrian source rocks and the Lower Ordovician Lower Qiulitage Group and Penglaiba Formation, and it is widely distributed throughout the entire basin. In this study, the oil-gas charging process of the upper petroleum system was reconstructed using the streamline method, and it was found that the characteristics and trends of the streamline variations were consistent with those of the lower petroleum system (Figure 8). This indicates that the oil-gas charging, migration, and accumulation trends of the petroleum system have significant inheritance characteristics. It can be seen from Figure 8 that the uplift of the upper petroleum system and the dominant migration channel in the slope are positive zones for oil-gas accumulation. Unlike the lower petroleum system, the Manjar petroleum system is characterized by significant streamline accumulation in the Guchengxu uplift and the northern part of the Tarim Basin, and the oil-gas migration and accumulation trends increase significantly. This will be discussed further below.
Regarding the Lower Qiulitage Group, oil-gas indications have been observed in wells BT5 and MB1 in the Bachu area and well ZS1 in the middle of the Tarim Basin. Abnormal gas measurements have been obtained at 7158–7510 m in well YQ6 in the Lower Qiulitage Group in the northern part of the Tarim Basin, and oil patch and oil stains have been observed in well TS1 in the Lower Qiulitage Group [15]. All of these observations indicate a promising oil-gas potential. Based on the thermal evolution of the Lower Cambrian source rocks, the oil-gas migration and accumulation trends of the Lower Qiulitage Group in the Hercynian (Figure 8(a)) and Himalayan (Figure 8(b)) were reconstructed and modeled. The modeling results are consistent with the above oil-gas indications in the single wells and the hydrocarbon generation and expulsion histories of the single wells.
5. Discussion
The Cambrian oil-gas migration process in the Tarim Basin is an important basis for evaluating the deep oil-gas resources [17, 33, 52]. However, it is extremely difficult to study the migration in the Cambrian deep petroleum system in the Tarim Basin, and there are few reports on the regularity of the oil-gas accumulation due to the low degree of exploration [3]. Through thermal history reconstruction (Figure 3), our basin simulation revealed that the Cambrian source rocks in the Tarim Basin are mainly in the highly mature and overmature stages. The simulation of the hydrocarbon charging phases in the different geological periods (Figure 4) revealed that the oil generation in the source rocks predominantly occurred from the Caledonian to Hercynian, and the gas generation occurred from the Indosinian to Himalayan. The distribution range of the effective source rocks was determined from the planar thermal evolution of the source rocks (Figure 6), and the fluid potential distributions of the Upper and Lower Cambrian hydrocarbon systems were simulated based on the geomorphology provided by the paleotectonic evolution (Figures 7 and 8).
Based on the fluid potential modeling conducted in this study, the paleostructural characteristics of the petroleum system and the maturity of the source rocks were comprehensively considered to reconstruct the forms and characteristics of the streamline distribution during the critical time periods and to identify the four development models of the oil-gas charging and migration in the Cambrian (Figure 9). The four oil-gas charging models were significantly different. The first model was characterized by multisource, multiphase, and multidirectional accumulation (Figures 9(a) and 9(b)). Owing to the combined charging influences of the multiple petroleum systems, the oil and gas were charged from multiple directions toward the low-potential zone. Owing to the strong oil-gas charging intensity, the oil and gas existed in the phase state. It was mainly distributed in the Manjar, Awati, and Tanggubasi petroleum systems, and the oil-gas accumulation occurred in the Katake uplift and the Shuntuoguole low uplift. The second model was characterized by multisource, multiphase, and single-directional accumulation (Figures 9(c) and 9(d)). Owing to the combined charging influences of the multiple oil-gas petroleum systems, the oil and gas migrated in a single direction, from the depression (high fluid potential zone) to the uplift (low fluid potential zone). Owing to the large oil-gas charging intensity, an oil-gas reservoir was mainly formed. This was the typical model in the intersection zone of the Maigaiti and Tanggubasi petroleum systems, and the oil-gas accumulation occurred in the southwest Bachu uplift. The third model was characterized by single-source, multiphase, and multidirectional accumulation (Figures 9(e) and 9(f)). Under the control of a single petroleum system, the oil and gas migrated from the side and bottom into the low-potential zone. Owing to the influence of the differential displacement, a gas reservoir was mainly formed. This was the typical model in the Tabei uplift, and the oil-gas accumulation mainly occurred in the Manjar petroleum system. The fourth model was characterized by single-source, multiphase, and single-directional accumulation (Figures 9(g) and 9(h)). Owing to the influence of the single petroleum system, the oil and gas migrated along a single direction, from the high potential zone to the low-potential zone. In addition, a gas reservoir was mainly formed due to the differential displacement. This was the typical model in the petroleum system in the Bachu and Maigaiti slope, and the oil-gas accumulation mainly occurred in the southwest Bachu uplift.
Previous studies have chiefly analyzed the geological features and predicted that the uplift may be a favorable area for deep oil-gas accumulation based on the structural level and oil-gas indications [26, 53], but few studies have considered the oil-gas charging intensity and migration model, and therefore, they lack a basis for evaluating the favorable areas.
In this study, the hydrocarbon migration direction and path of the deep Cambrian oil and gas migration were determined from the perspective of the kinetic energy and potential energy of the fluid based on the source rock and paleogeomorphic factors. Our research results are consistent with the current exploration situation, indicating that the above research represents good progress. The analysis of the results of the basic fluid potential simulation revealed that the Katake uplift was the most favorable zone for Cambrian oil-gas migration and accumulation, and it was a multisource and multiphase accumulation zone of the Manjar petroleum system, Awati petroleum system, and Tanggubasi petroleum system. As a result, the high oil-gas charging intensity and long charging time were beneficial to oil-gas entrapment in the Cambrian system. The Shuntuoguole low uplift was charged from the Manjar petroleum system and the Awati petroleum system and had an inferior oil-gas charging intensity (Figure 10). The southwest Bachu uplift was charged from the Maigaiti petroleum system and the Tanggubasi petroleum system, which was beneficial to Cambrian oil-gas accumulation. Owing to the long-term and continuous charging from the Manjar petroleum system, the Tabei uplift was also a favorable zone for Cambrian oil-gas accumulation. The comparison of the oil-gas migration and accumulation trends of the Upper and Lower Cambrian petroleum systems indicates a better consistency (Figure 10). It reflects the significant control of the paleostructural evolution on the ultradeep oil-gas accumulation in the Cambrian system, and it further reveals that the traps of the dominant migration channel of the oil-gas accumulation may be a promising target for the development of the ultradeep paleo oil-gas reservoir in the Cambrian system. The above results are consistent with the potential of the current oil-gas resources explored in the current shallow layer, reflecting the effectiveness and high application value of the proposed method.
6. Conclusions
The secondary migration of deep oil-gas system first identified the thermal evolution history and model of source rocks. The history of the hydrocarbon generation in the Lower Cambrian source rocks in the Tarim Basin was characterized by early oil generation and late gas generation, and three models occurred under the influence of the paleostructural evolution. The continuous thermal evolution model occurred in the depression, e.g., the hydrocarbons were generated in the Early Ordovician. The peak liquid hydrocarbon generation occurred from the Devonian to the Carboniferous, the peak gas generation occurred in the Early Permian, and the hydrocarbon generation was not interrupted. The continuous thermal evolution model occurred in the slope, i.e., the hydrocarbons were generated in the Upper Ordovician strata. The hydrocarbon expulsion occurred in the Carboniferous, the peak liquid hydrocarbon generation occurred in the Permian, and the peak gaseous hydrocarbon generation occurred in the Triassic. The hydrocarbon generation process occurred in stages. The fast thermal evolution model occurred in the mountain front in the peripheral basin. The degree of thermal evolution increased rapidly after the Miocene, and the oil generation and gas generation reached a peak. This was the late fast hydrocarbon generation model.
There are four models of the fluid potential developed in the Cambrian ultradeep reservoir in Tarim Basin, i.e., multisource, multiphase, multidirectional accumulation; multisource, multiphase, single-directional accumulation; single-source, multiphase, multidirectional accumulation; and single-source, multiphase, single-directional accumulation. The multisource, multiphase, multidirectional accumulation and the multisource, multiphase, single-directional accumulation were the most beneficial models for oil-gas accumulation due to the strong charging intensity and long charging time.
The migration trend in the Upper and Lower Cambrian petroleum systems in the Tarim Basin has significant inheritance characteristics. The streamline accumulation in the uplift and slope reflects the dominant migration channel, which is favorable for oil-gas accumulation. The Katake uplift and the southwest Bachu uplift experienced multisource charging accumulation and are the most favorable oil-gas accumulation zones in the Cambrian petroleum system. The east Bachu uplift and the Tabei uplift are more favorable oil-gas accumulation zones due to continuous charging of the single petroleum system.
The basin modeling technique can provide an effective reference for evaluation of the migration and accumulation in the Cambrian petroleum system in the Tarim Basin. The prerequisite is geological model data for the thermal evolution of the source rocks and the evolution of the top structure of the reservoir.
Data Availability
The data that support the finds of this study are available from the corresponding author upon reasonable request.
Conflicts of Interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Acknowledgments
This research was supported by the Regional Innovation Cooperation Project (grant number 21QYCX0048) of the Science and Technology Department of Sichuan Province. We are grateful to the SINOPEC Northwest Company and the Research Institute of Petroleum Exploration & Development for providing some important data.