Overpressure of Deep Jurassic System in the Central Junggar Basin and Its Influence on Petroleum Accumulation

Abstract

New discoveries and breakthroughs have been made in recent years in the deep parts of the central Junggar Basin, where the Jurassic reservoirs are unconventionally dense with abnormal overpressure development. The development and distribution of overpressure in this basin and the influence of overpressure on petroleum accumulation were analyzed. There are two extremely high overpressure systems in the Jurassic Badaowan and Xishangyao formations, from where the abnormal overpressure in the strata overburdened Jurassic reservoirs was transferred. Paleopressure simulations show that hydrocarbon generation pressurization of the main source rocks in the Badaowan Formation is a process characterized by at least two phases of overpressure increase followed by a phase of overpressure release. Overpressure inhibits the thermal evolution of source rocks in the study area, resulting in lower values of maturity parameter Ro at depths > 4500 m compared with the normal values at depths < 4500 m. The deep reservoirs > 4500 m are very dense, with strong compaction and little retention of primary pore space, indicating the overpressure did not protect the primary pores, while the over-pressured acidic fluid promoted the formation of dissolved pore space. Overpressure and faults are two key factors of petroleum migration, and they jointly control petroleum accumulation in the central Junggar Basin.

1. Introduction

Oil and gas resources in deep parts of the basin have gradually become the strategic target of petroleum exploration and development [1,2,3]. Overpressure is an important controlling factor for deep oil and gas accumulation in the deep basins [4,5,6,7,8,9]. The formation of oil and gas reservoirs in sedimentary basins is mostly related to overpressure, and the existence of overpressure tends to facilitate the accumulation and preservation of oil and gas, which is conducive to the formation of large oil and gas reservoirs [10,11,12,13]. For example, Yang et al. (2016), when studying the relationship between overpressure distribution and oil and gas accumulation in the central area of Junggar Basin, believed that oil and gas were often enriched near the top surface of the overpressure [14]. In the deep part of the basin (>4500 m), high temperature and high pressure not only control the evolution of organic matter and hydrocarbon phase state but also play an important role in reservoir space as well as petroleum migration and accumulation [15,16,17,18,19]. In addition, overpressure could cause t serious drilling accidents like venting, leaking, blowouts, kicks, and fluid infiltration during drilling [20,21]. Therefore, the study of deep overpressure has important practical significance in petroleum exploration [9,22,23].

As an important oil-bearing basin in western China, the Paleozoic and Mesozoic Junggar Basin has achieved great progress in deep oil and gas exploration in recent years [17,24]. A number of key deep exploratory wells in the central and southern margin of the basin have consistently produced high-yielding industrial oil and gas flow. The overpressure in the deep layers (>4500 m) of Junggar Basin is very developed [25,26]. For example, the pressure coefficient of the Jurassic system in the MS1 well in the central part of the basin reaches 2.3 at a burial depth of 6000 m, showing a remarkably strong abnormal overpressure. Previous exploration practices showed that overpressure in the Jurassic system is very developed in the central Junggar Basin, such as the Mosowan area [27,28] and the east slope of the depression in the west of Pen 1 well [29,30]. However, the research on the effect of overpressure on the elements for reservoir forming in the deep strata of depth > 4500 m is limited [31,32]. The study area in the central Junggar Basin is located on the east slope of the Fukang Depression, which is the central depression in the basin. Recently a number of wells in the central part of this basin were drilled to the deep Jurassic system with burial depth > 5500 m, for example, the D3 well, which drilled to Jurassic layers of approximately 6000 m. Therefore, this block is one of the deepest drilling spots in this basin, and its depth-related overpressure is typical.

Starting from the study of Penshen 2 well in the Mosowan area in the 1990s, numerous studies have been involved in the distribution characteristics, the genetic mechanism of abnormal overpressure as well as its influence on petroleum accumulation in the Junggar Basin (e.g., [14,28,30,33,34,35,36]). The study of deep oil fields is relatively late, beginning with the effective reservoir analysis of the main exploration target areas [37,38]. In recent years, studies of source rocks, tectonic evolution, reservoir formation, and enrichment laws of petroleum in the deep parts of this basin have begun [39,40,41]. In general, there are two deficiencies in the previous research on the abnormal pressure in the deep parts of the Junggar Basin: (1) Most of the studies only focus on one aspect of abnormal pressure research, which is mostly related to abnormal pressure prediction, thermal evolution and reservoir development characteristics under overpressure conditions, while there are few comprehensive studies on the influence of overpressure on oil and gas accumulation; (2) Most of them are related to the development characteristics and prediction of modern pressure, but there are few studies on the prediction and evolution of ancient overpressure.

Based on the data of oil test, well logging, seismic analysis, and laboratory geochemistry analysis, the prediction of overpressure, the evolution of paleo-overpressure, and the effects of overpressure on the thermal evolution of source rocks, reservoir porosity and permeability, hydrocarbon migration, and accumulation are comprehensively studied in this study (Figure 1). Relevant knowledge is helpful in improving understanding of the conditions and processes of petroleum accumulation in the deep over-pressured strata of the sedimentary Basin and has a guiding role for petroleum exploration in deeper parts of the basin.

2. Geological Setting

The study area is located in the east of Fukang Depression in the central Junggar Basin (Figure 1). It is a monocline structure low in the southwest and high in the northeast. This block has a complex tectonic background and experienced a tectonic evolution stage such as a strong uplift and overall tilt in the Jurassic.

The oldest strata in Junggar Basin are Carboniferous and Permian. The sedimentary period of the Carboniferous system developed shallow sea or transitional facies. During the Early Permian sedimentary period, coarse clastic rocks were widely developed around the basin. In the Middle Permian period, the lake basin formed initially. In the middle to late Permian sedimentary period, the basin mainly developed lacustrine sediments, and the thickness of the source rocks could reach thousands of meters. By the middle and end of the Triassic, the lake had developed to basically cover the whole basin, with semi-deep lacustrine sediments developing in the middle of the basin and shallow lacustrine sediments developing in the margin. Therefore, from the beginning of the Carboniferous period to the early Jurassic period, the settlement of the study area was relatively stable, with the characteristics of cratonic basins [42,43].

The strata including the Badaowan Formation (J₁b), Sangonghe Formation (J₁s), Xishanyao Formation (J₂x), and Toutunhe Formation (J₂t) were developed in the Jurassic system. During the Jurassic period, vertical deposition evolved into rivers, lakes, and deltas, reflecting the characteristics of rapid deposition. Lake and braided river delta deposits are mainly developed in J₁b and J₁s. The J₂x developed mire and lake deposits from bottom to up. During the sedimentary period, the climate of the J₂t was semi-arid, the tectonic movement was strong, and meandering river sediments were mainly developed. On the whole, the paleoclimate evolved from a subtropical warm and humid to a tropical arid and sedimentary environment developed from a semi-deep lake and shallow lake to a braided river delta and meander river depositional systems in the Jurassic period [26].

3. Methods

More than 50 Jurassic sandstone samples were analyzed by microscopic analysis of ordinary slices (monopolarized) and cast slices. Analysis of rock diagenesis, reservoir space, and pore characterization were performed through more than 200 blue epoxy resin-impregnated thin sections. The instrument for the fluid inclusion observation and analysis is the latest product THMS 600G hot and cold table of Linkam (England). The analysis accuracy is ±0.1 °C. The microscope used is Olympus made in Japan, with a 100 × 8 mm telephoto working lens. Details of the methods can be found in the previous studies [36].

A total of 15 Jurassic mudstone samples were subjected to vitrinite reflectance (Ro) measurements, which were performed on randomly oriented macerals using conventional microphotometric methods [44]. A Leitz MPV-SP system which was calibrated with a Leitz synthetic Leuco–Saphir–Prism with 0.515% Ro standard was used for the Ro measurements. The microscope was calibrated with integrated optical zero standard before the measurements. The data were considered meaningful when the standard deviation for a range of Ro was less than 0.10% and the standard deviation of Ro was no more than 0.05% for most samples.

Geochemical parameters such as molecular markers C₂₉ steranes and dimethyl dibenzothiophene (DMDBT) were obtained by gas chromatography-mass spectrometry (GC-MS) analysis of extracts from crude oil and oil sands. The chromatographic column was HP-5 (0.25 μm × 0.25 mm × 30 m) with helium as the carrier gas. An Agilent 6890GC-5975I MS (California, USA) equipped with a DB-5 elastic capillary column of fused silicon (60 m × 0.25 mm × 0.25 μm) was used to analyze the hydrocarbons through the GC-MS method [45,46]. The split ratio was 20:1, the carrier gas was helium. The electron energy was 70 eV, the scan rate was 0.46 can/s, and electron-impact ionization was employed.

The Bowers (2002) method was used to predict the formation pressure of 8 wells [47]. The formation pressure in 2D profiles was predicted using seismic velocity data and the enhanced Fillippone formula approach [48]. Paleo-pressure was simulated by using PVTsim software (v.20) combined with the information on reservoir fluid inclusions [49]. These methods are described more in the text. The seismic, drilling, well logging, and oil production test data used in this study was provided by the Sinopec Shengli Oilfield Company (Shandong Province, China).

4. Results

4.1. Measured Formation Pressure

Drill stem testing (DST) data was used to analyze formation pressure characteristics in selected wells in the study area. According to the measured pressure data in Figure 2, the depth of the abnormal overpressure layer varies among wells in the study area, and nearly all of them have abnormal overpressure at depths > 4500 m. The abnormal overpressure is widely distributed in Jurassic strata, from the lower Jurassic J₁b to the upper Jurassic J₂t, and the pressure coefficient in some sections is >2.0. For example, in the 5687.7 m~5699.3 m interval in the D3 well, the maximum pressure coefficient is 2.0. In the 5328.9~5335.6 m interval of the D2 well, the maximum pressure coefficient is 2.07. The measured formation temperature during drilling and oil production reveals that the formation temperature is in the range of 100~140 °C, while the geothermal gradient is low (2.0–2.5 °C/100 m), and the geothermal gradient shows small change with the increase of depth in the over-pressured section.

4.2. Bowers Method to Predict Formation Pressure in Logs

In this study, the Bowers method [47] was used to predict the overpressure in several wells. Bowers provided two approaches “loaded” and “unloaded” to calculate formation pressure, both of which introduced two factors, A and B, in his study of formation pressure in the Gulf of Mexico. The link between acoustic velocity and vertical effective compressive stress must be established in order to determine these two parameters.

The formation pressure for the “loaded” condition is calculated as:

$$p=p_v-{\left({\displaystyle \frac{{10}^6\left(\frac{1}{\mathsf{\Delta }t}-\frac{1}{\mathsf{\Delta }{t}_m}\right)}{A}}\right)}^{{\displaystyle \frac{1}{B}}}.$$

(1)

The formation pressure for the “unloaded” condition is calculated as:

$$p=p_v-{\left({\displaystyle \frac{{10}^6\left(\frac{1}{\mathsf{\Delta }t}-\frac{1}{\mathsf{\Delta }{t}_m}\right)}{A}}\right)}^{{\displaystyle \frac{1}{B}}}{\left({\sigma }_{max}\right)}^{1-U}.$$

(2)

In the two equations, Δt_m is surface acoustic velocity, generally 660 μs/m; A, B—constants obtained by fitting; U—subsidence or uplift coefficient, generally 3~8, there was little variation in the same study area, and 5 was applied in this study.

The two parameters A and B required to calculate formation pressure were determined by establishing the link between vertical effective compressive stress and acoustic velocity, using wells D1 and D2 as examples. Vertical effective compressive stress and acoustic velocity have the following relationship:

$$v_p=v_{ml}+A{\sigma }_e^B.$$

(3)

σ_e—vertical effective compressive stress; v_p—acoustic velocity; v_ml—acoustic velocity at the baseline of the mudstone, generally, the acoustic velocity at the surface is 1520 m/s.

Figure 3 showed that the sonic velocity tends to decrease when reaching a certain depth according to the relationship between formation acoustic velocity and the vertical effective compressive stress at the same depth. There is an exponential function relationship between the v_p–v_ml and the effective compressive stress in Wells D1 and D2, as shown in Figure 3, and the correlation coefficients are 0.6669 and 0.6954, respectively. According to these equations, it is determined that the parameters A and B of Dong 1 are 1019.4 and 0.022, respectively, and the parameters A and B of Dong 2 are 973.5 and 0.023.

The prediction results show that the formation pressure coefficients in Jurassic sediments in the two wells ranged from 1.2~2.0. The top boundary depth of the abnormally high pressure is generally about 4600 m, corresponding to the top of J₂t in D1 and J₁s in D2 well, respectively, above which is the normal pressure system (Figure 4). The Jurassic intervals of both wells can be divided into upper and lower overpressure systems. The overpressure in the lower system is generally stronger than the upper one, and the maximum pressure coefficient is >2.0, which generally occurs in the lower pressure system. Therefore, the lower part can be referred to as a super strong overpressure system.

4.3. Pressure Prediction in Stratigraphic Profiles Based on Seismic Velocity

Seismic data can be used to predict formation pressure in areas where no drilling is taking place. Fillippone [50] first proposed an equation to determine formation pressure using layer velocity of seismic waves and then advanced it in 1982. It can determine the formation pressure through the layer velocity and does not require the establishment of a normal compaction curve, thus it is suitable for estimating formation pressure before drilling. The Fillippone formula was improved by Yun [48] by introducing a correction coefficient as follows:

$$p=F\left(v\right){\displaystyle \frac{v_{\max }\left(H_i\right)-vi\left(H_i\right)}{v_{\max }\left(H_i\right)-v_{\min }\left(H_i\right)}{p}_o}$$

(4)

where

$$F\left(v\right)=0.16877{\mathrm{e}}^{0.00047v},$$

(5)

p—formation pressure of the i-th layer; F(v)—layer velocity correction factor; p_o—overlying formation pressure, MPa; $v_{\max }\left(H_i\right)$—maximum formation velocity, m/s; $v_{\min }\left(H_i\right)$—minimum formation velocity, m/s; $vi\left(H_i\right)$—layer velocity of the i-th layer.

4.3.1. Acquisition of Seismic Interval Velocities

In this study, the seismic interval velocity was obtained mainly through Jason simulation software (8.0), which is a combination of well and seismic inversion software and can convert the stacking velocity into the seismic wave velocity. The Vel Mod module in Jason simulation software can be used to obtain information about the seismic wave velocity. The east–west profile of the survey line crossing Well D6 is shown in Figure 5. The inversion of the seismic interval velocity profile shows that the low-velocity zone is generally located in the J₂t, the corresponding top depth is about 4500 m~5300 m, and the bottom depth is about 7000 m.

4.3.2. Prediction of Formation Pressure Based on Seismic Wave Velocity

After extracting the velocity data from the seismic information, the formation pressure in the profile was calculated by the Fillippone Equation (4). As shown in Figure 6, the distribution of the simulated pressure coefficient can clearly show the spatial development of overpressure in the profile. Figure 6 shows that the whole Jurassic system in the profile is an almost overpressured system with the pressure coefficient generally ranging from 1.2 to 2.0.

4.4. PVT Simulation of Paleo-Pressure

In the Jurassic sandstone reservoirs, hydrocarbon inclusions and brine inclusions are mainly developed, among which oil–water symbiotic inclusions are the most abundant (Figure 7). The shapes of inclusions are mainly rectangular, elongated, elliptical, and nearly circular as well as irregular shape. The size of inclusions is widely distributed, with a range of 4 × 3 μm~20 × 14 μm. Microscopic observation shows that quartz is the primary host mineral for inclusions, and these inclusions mostly exist in the intra-grain fractures of quartz.

The homogenization temperature of the inclusions was determined, and some parameters of the oil inclusions, such as the volume of the oil inclusions and the gas–liquid ratio, were calculated by confocal microscopy (Figure 8). On the basis of hydrocarbon inclusion information, PVTsim software was used to simulate the PVT of fluid inclusion and calculate paleo-pressure [49].

The ratio of the obtained paleo-pressure to the hydrostatic pressure at the corresponding depth was calculated, and the general evolution history of the pressure coefficient was established (Figure 9). The pressure evolution can be separated into two main stages, as shown in Figure 9. On the whole, the first stage was the overpressure reduction period from the end of the Jurassic to the end of the Cretaceous, and the pressure coefficient was close to 1.0 at about 80 Ma ago. The second stage is the overpressure increasing period from the Paleogene to the present. Therefore, although the Jurassic overpressure formed early, it was released at the end of the Mesozoic due to the uplift and denudation of tectonic movements, and the present-day overpressure was formed in late time in the Cenozoic period.

5. Discussion

5.1. Relationship between Overpressure and Thermal Evolution of Organic Matter

There are three different viewpoints regarding how overpressure affects the thermal evolution of organic matter in source rocks. The first is that overpressure inhibits the thermal evolution of organic matter to hydrocarbons [51,52]; for example, Price and Wenger [53] conducted an experiment of aqueous pyrolysis in a closed system to investigate the effect of fluid pressure on hydrocarbon generation, and the results showed that the increase of pressure significantly inhibited the thermal evolution of organic matter and hydrocarbon generation. The second is that overpressure accelerates hydrocarbon evolution, for example, Braun and Burnham [54] argued that high pressure can promote oil cracking, and the cracking rate increases with the increase of pressure at high temperatures. The third is that the overpressure has no apparent impact on hydrocarbon evolution, with an example of Monthioux [55], who believed that different pressures do not produce detectable effects on the catagenesis of organic matter based on high-temperature-pressure pyrolysis experiments.

The measured Ro in the study area shows that the Ro of the J₂x mudstone samples in the D1 well ranges from 0.7% to 0.81%, and the Ro of J₁s and J₁b in the D6 well ranges from 0.74% to 0.82%; the Ro of J₂x and J₁s in D3 well ranges from 0.81% to 0.84% and 0.84% to 0.87%, respectively. Figure 10 demonstrates that the measured Ro of these Jurassic mudstones in the study area is almost all lower than the Ro in normal evolutionary tendency, indicating that the overpressure in the study area has inhibited the organic matter thermal process, which caused the deep Jurassic organic matter in the study area has been kept in a mature state in the oil window.

5.2. Effect of Overpressure on the Reservoir

5.2.1. Characteristics and Causes of Overpressure in Reservoir

The over-pressured Jurassic reservoirs in the central Junggar Basin present the following characteristics. (1) There is a transition interface in the content of clay minerals that corresponds to the 4800 m overpressure interface, where kaolinite starts to decrease relatively, while mixed layers of illite and montmorillonite increase relatively, indicating that there is mineral transformation and dewatering pressurization (Figure 11). (2) The carbonate rocks in the reservoir under the overpressure interface are dissolved by water with low salinity, and then reprecipitated on the overpressure interface, leading to abrupt changes in the content of carbonate rocks above and below the overpressure interface [56]. (3) The process of dissolution and reprecipitation of carbonate rocks leads to a sharp decrease in porosity and permeability at the overpressure interface, and the porosity decreases from 20% to about 10%, and the permeability decreases to 0.1 × 10⁻³ μm. Such “load transfer” [57,58] mechanism of “dissolution and re-cementation” in grain edges of sandstone may be a way to generate reservoir overpressure. The dehydration caused by mineral transformation and diagenetic cementation may be a way to cause overpressure in the reservoir, but the level of overpressure produced by this mechanism is usually limited [59,60,61].

The reservoirs were impacted by the abnormal overpressure in the conversion of organic matter to hydrocarbons. Oil and gas gradually discharge outward from the source rocks with the change of pressure. In the study area, the overpressure was mainly produced in the Jurassic J₁b and J₂x source rock systems. Such overpressure should be related to the pressurization effect caused by the massive generation of oil and gas, especially the Jurassic coal-bearing measures generated large amounts of light oil and gas, which is prone to have a considerable pressurization effect. The overpressure of the J₂t is likely a result of the overpressure transfer. The overpressure fluid migrated upward to the J₂t along faults from the lower Jurassic, resulting in the formation of overpressure in the upper Jurassic reservoirs.

5.2.2. Influence of Reservoir Overpressure on Compaction and Primary Porosity

At present, some studies believe that abnormally high pressure has an impact on diagenesis in reservoirs, such as hindering compaction, weakening cementation, and promoting dissolution and fracture formation [62,63,64]. Particularly, it is important for deep tight reservoirs, the effect of hindering compaction by abnormal overpressure on deep reservoirs can reduce the loss of primary intergranular pores and preserve the primary remaining intergranular pores. Hence, overpressure can increase reservoir pore space, enhance seepage capacity, and ultimately effectively improve reservoir quality through these ways. For example, this effect is particularly prominent in the deep tight Jurassic reservoirs with “early long-term shallow burial and late rapid deep burial” in the southern Junggar Basin, which is dominated by primary residual intergranular pores.

Figure 12 shows that in the study area, the Jurassic reservoirs are characterized by low- to ultra-low-porosity on the whole. The J₂t has the highest porosity and permeability of Jurassic reservoirs, followed by J₁s, J₂x, and J₁b. Within the over-pressured reservoirs of the J₂t, the primary pore spaces have almost disappeared and secondary dissolution pores spaces are dominant. Microscopic observation shows that the contact mode of sandstone grains in the Jurassic reservoirs is mainly line contact, the calcite cementation was common, and almost no macroscopic primary pores were found, except some residual intergranular pores and intra-granular secondary pores.

For example, as Figure 13 shows, the rock suffered from strong compaction in the Jurassic reservoirs of the D1 and D7 wells. The J₂t of D1 Well shows remarkable overpressure, with a measured formation pressure of 84.81 MPa and a pressure coefficient of 1.96 at 4870~4875.5 m, corresponding to oil and gas production of 66.26 t/d and 47261 m³/d, respectively, but the porosity is mostly <5%. The contrast between abnormally high overpressure and low porosity suggests that the present overpressure did not protect the primary pore spaces.

The J₂t of the D7 well shows remarkable overpressure and the pressure coefficient can reach 2.0 (Figure 14). The porosity of the J₂t reservoir is in the range of 5–10%, and the porosity of J₁s is even lower. There is a close relation between porosity and permeability, but there is no clear correlation between pressure coefficient and porosity. According to the paleo-pressure recovery of reservoir fluid inclusions, the early overpressure was discharged at the end of the Mesozoic, and the present overpressure was formed in late time during which strong compaction have already occurred; consequently, the overpressure did not play an important role in protecting the primary pore space of these reservoirs.

5.2.3. Effect of Overpressure Fluid on Secondary Pores and Fracture

The dissolution is the main factor for the improvement of the physical properties of sandstone in the Jurassic reservoirs in the study area. The lower the content of soft cuttings and cement, the coarser the particle size, and the more conducive to the occurrence of dissolution [65]. Numerous studies have suggested that abnormally overpressure facilitates dissolution [66,67]. Late overpressure hydrocarbon fluids carrying organic acids can transform the reservoir, creating secondary pores and improving its pore-permeability properties. Although the overall porosity and permeability of Jurassic in the study area are low, there are also intergranular and intra-granular dissolution pores of feldspar and debris in the reservoir samples under the microscope, and the intergranular dissolution pores are relatively abundant (Figure 15), which might be related to the dissolution of over-pressured hydrocarbon fluids. Such high-quality reservoirs with high porosity and permeability are the primary targets of oil and gas exploration in the deep parts of the basin.

Given that the pressure coefficient of many wells is greater than 1.9, such high pressure may exceed the fracture pressure of the formation and promote the formation of micro-fractures in deep tight sandstones, thereby improving reservoir connectivity and enhancing reservoir permeability [68]. This phenomenon has been reported in other areas of the central Junggar Basin. For example, the core data of well Pc2 in the central Junggar Basin showed that there are a large number of vertical and horizontal micro-fractures in the sandstone and mudstone near the over-pressured layer at a depth of 4400 m, some of which are filled, and the porosity of micro-fractured mudstone reaches 18–20% [69]. However, in the Jurassic over-pressurized interval of the study area, only a small number of fractures were observed locally, which led to an abnormal increase in permeability; while such development of fractures is not extensive in the Jurassic reservoirs in the study area, and this result may be related to the late formation of overpressure and the high content of soft cuttings in the reservoirs, which have strong plasticity and make the rocks not easy to fracture.

5.3. Relationship between Overpressure and Petroleum Migration

Clarifying the depth of overpressure distribution has an important guiding role in effectively reducing the occurrence of drilling accidents in reservoir development. Figure 16 shows the contour map of burial depth at the top boundary of overpressure. The burial depth of the overpressure top interface in the study area decreases gradually from southwest to northeast, ranging from 4200 m to 5800 m.

Figure 17 presents the distribution of the maximum pressure coefficients shown by single well data in the Jurassic formation, represented by J₁b and J₂x which contains the hydrocarbon source rocks in the study area. The pressure coefficients in J₁b and J₂x both show a decreasing trend from southwest to northeast. This pressure gradient acts as an important driving force for the oil and gas migration from southwest to northeast. At the same time, the J₁b has a higher-pressure coefficient than the overlying formations, thus there is a vertical driving force for hydrocarbon discharge from the lower source rocks to overlying reservoirs. Driven by abnormal overpressure and the overpressure gradient, it is conducive to the accumulation of oil and gas in the northeast traps. This is consistent with the direction of hydrocarbon migration traced by geochemical parameters.

The ratios between isomers of dimethyl dibenzothiophene (DMDBT) as maturity parameters can effectively trace the direction of hydrocarbon charging [70,71,72,73,74]. The ratio 2,6+3,6-DMDBT/1,4+1,6-DMDBT and the ratio 2,7+3,7-DMDBT/1,4+1,6-DMDBT were used as oil migration tracers in this study (Figure 18). Both tracers show a decreasing trend from the southwest deep depression to the northeast slope area, which is generally consistent with the direction suggested by the decreasing pressure gradient. It demonstrated that there are likely two migration directions of crude oil as shown in Figure 18. Oil and gas are most likely to accumulate in the traps of structural high points of the eastern slope, such as traps in the D2 and D6 wells.

Figure 19 shows the distribution of the pressure coefficient on the geological profile crossing several wells. The simulation results reveal that oil and gas reservoirs are generally distributed in the strata surrounding the overpressure top surface. The over-pressured fluid migrates vertically and laterally along the fault and the sandstone, respectively. In the study area, large regional faults are developed with large dips, most of which are >72°, and extend to the top boundary of the J₂t, which provides suitable channels for vertical petroleum migration from the lower Jurassic source rocks to the J₂t (Figure 19). Large sandstone bodies with favorable connectivity are generally developed in J₁s, and the oil and gas generated in J₁b can also reach J₁s through strike-slip faults, then migrate laterally along the sandstone in J₁s, and finally migrate upwards through faults to J₂t. Besides the oil accumulation in the tectonic traps in overlying strata far from source rocks under the communication of faults, the highly mature oil and gas generated in the “late time” can accumulate in the lithologic and stratigraphic traps near the source rocks. Geochemical parameters in Figure 19 show a typical migration effect during the migration of over-pressured hydrocarbon fluid from source rock to reservoir in the Jurassic system in the study area. The ratio of C₂₉ steranes ββ20R/αα20R in crude oil samples is mostly above 1.0, the highest is >1.9, and the average is 1.63, while this ratio in source rock samples is lower (<1.0).

Studies on overpressure and oil and gas accumulation cover the causes of overpressure, the identification method system of overpressure causes, the influence of overpressure on oil and gas accumulation factors, and the dynamics of oil and gas migration, especially the dynamic relationship between overpressure evolution and oil and gas accumulation process. Due to the limitations of data and methods, these contents cannot be comprehensively and profoundly expounded in this paper. Some aspects of the research will be strengthened in future research.

6. Conclusions

(1)

The Jurassic system in the central Junggar Basin is generally developed with abnormal overpressure, and the pressure coefficient can be as high as 2.0 or higher. The Bowers method shows that the vertical pressure system can be divided into three parts: the normal pressure system in the Cretaceous to Cenozoic strata, the super strong overpressure system in the Lower Jurassic, and the overpressure system in the upper Jurassic. The super strong overpressure in the Lower Jurassic is mainly caused by hydrocarbon generation, and the overpressure system in the upper Jurassic is the result of upward migration and transfer of overpressure fluid from the lower strong overpressure system. The paleo-pressure simulation shows that the overpressure formed in the early Jurassic has a history of release, and the present overpressure was formed in the late Cenozoic period.

(2)

The abnormal overpressure environment of the Jurassic results in the negative anomaly of the maturity parameter Ro of organic matter in the source rocks, which indicates that the thermal evolution has been inhibited to a certain extent. However, due to the late formation time of overpressure in the study area, it did not slow down the compaction effect on the reservoir and therefore not protect the primary pores. But, the overpressure hydrocarbon fluid promoted the formation of the dissolution pores in the reservoirs.

(3)

The overpressure in the study area plays an important role in the petroleum migration, and there is a general gradient of decreasing overpressure from southwest to northeast. In addition, the top boundary of the overpressure system rises in the northeast direction, so the hydrocarbon fluid migrates from southwest to northeast in general. The fault is the main channel of petroleum upward migration, and overpressure and fault jointly control the accumulation of Jurassic oil and gas in the study area.