Triassic Baikouquan Formation Research Articles

Prediction of favorable areas for oil accumulation in outer-source tight reservoirs under the control of lateral migration distance: A case study of the Baikouquan Formation, Mahu Sag, Junggar Basin, China

There is a starting pressure gradient (SPG) for oil migration in tight reservoirs (TRs), and the SPG and the migration force jointly control the migration distance of oil. The key factor of oil accumulation in the tight glutenite reservoir (TGR) of the Lower Triassic Baikouquan Formation (T1 b) in the Mahu Sag is whether the oil can be laterally charged into the TRs. To analyze the lateral migration distances of oil in TRs and predict the favorable accumulation areas for oil, we have carried out a physical simulation experiment of oil charging on glutenite reservoirs of T1 b for obtaining the SPG of oil migration and knowing the relationship between SPGs and the reservoirs’ physical property. According to the basin simulation, we have obtained the pressure evolution of the source-rock formation as well as reservoir formation and the physical property evolution of the reservoir. Finally, we have predicated the favorable oil accumulation areas through calculating the distribution characteristics of SPGs as well as the theoretical distances of lateral migration of oil during the key oil accumulation period and considering the theoretical distance of the lateral migration of oil as the main controlling factor. Our results suggest that there is a SPG in the TGR of the T1 b and that there is a power function relationship between the SPG and the permeability. The theoretical lateral migration distance of oil in T1 b during the key oil accumulation period was the farthest in the northern sag, which was gradually shortened to the east, west, and south. In class I favorable areas, the reservoirs have good physical properties where overpressure has developed; in addition, the lateral migration distance of oil is far. Therefore, these are the most favorable areas for oil accumulation.

Three-dimensional in-situ stress modeling of tight conglomerate reservoirs: A case study of Triassic Baikouquan formation in the Mahu depression, Xinjiang Oilfield

As a tight conglomerate reservoir, the Baikouquan formation reservoir in the Mahu depression is vital heterogeneous. The development model of unconventional oil and gas fields such as shale gas is copied in the early development process. Advanced horizontal wells and volumetric fracturing technologies are adopted, with high development costs and low economic benefits. During the development of tight conglomerate reservoirs, there are typical problems such as underdeveloped natural fractures, complex fracture formation mechanisms during fracturing, and serious interlayer channeling in fractured wells. Practical results show that the adequate characterization of in-situ stress distribution plays a decisive role in the scientific and efficient development of tight conglomerate reservoirs. To accurately characterize the three-dimensional in-situ stress distribution law of conglomerate reservoirs, the paper selects the Mahu 131 demonstration well area. The mechanical parameters of the demonstration area are finely described through a series of core tests, well-drilled logging data, and seismic inversion data. As a result, the spatial distribution of essential parameters of the demonstration area has been established, such as the three-dimensional elastic modulus attribute volume and the three-dimensional Poisson’s ratio attribute volume. Further, an advanced finite element simulator and large-scale parallel computing technology establish the test area’s high-precision three-dimensional stress field model. Based on enormous fracturing data, microseismic data, and production data, quality control and correction of the three-dimensional stress field model are carried out. The results show that the established geomechanical model accurately reflects the direction, magnitude, and heterogeneity of the in-situ stress in the demonstration area. Through the three-dimensional minimum in-situ stress distribution, the three-dimensional horizontal stress difference distribution, the lithology characteristics of conglomerate, rock mechanical properties, and other factors in the test area, it is believed that the difference in interlayer stress is the main reason for the interlayer channeling of fracturing. According to the established high-precision in-situ stress model and the rational fracturing construction process, it can actively strengthen or weaken the instantaneous and local stress field and pressure field, from near field to far-field, and promote the expansion of hydraulic fractures in the desired manner.

Conglomerate Reservoir Pore Evolution Characteristics and Favorable Area Prediction: A Case Study of the Lower Triassic Baikouquan Formation in the Northwest Margin of the Junggar Basin, China

Conglomerate Reservoir Pore Evolution Characteristics and Favorable Area Prediction: A Case Study of the Lower Triassic Baikouquan Formation in the Northwest Margin of the Junggar Basin, China

Oilfield Water and Favorable Petroleum Exploration Targets for the Triassic Baikouquan Formation in the Slope of Mahu Depression, Junggar Basin

In this paper, we attempt to clarify the relationships between oilfield water and hydrocarbon distribution of the Triassic Baikouquan Formation, in the slope zone of Mahu depression, Junggar Basin, NW China, based on oilfield water mineralization degrees, diagenesis analysis, formation pressure coefficients, burial history, and thermal evolution processes. The results show that the study area can be divided into four zones according to the mineralization degrees, that is, (1) zone I: NaHCO3 + Na2SO4 type water with residual intergranular pores, porosity usually higher than 10%. The strata of zone I are generally buried shallow and influenced by leaching from atmospheric precipitation. This area contains normal edge and bottom water and has normal formation pressure coefficients (average 1.12); (2) zone II: CaCl2 type water with mainly compaction diagenesis, porosity usually less than 7% and high formation pressure coefficients (average 1.41); (3) zone III: NaHCO3 + CaCl2 type oilfield water with mainly feldspar dissolution diagenesis, porosity usually greater than 9% and high formation pressure coefficients (average 1.53); and (4) zone IV: CaCl2 type water, mainly compacted diagenesis with a few intergranular and feldspar dissolved pores, and high formation pressure coefficients (average 1.58). The mineralization degrees of the oilfield water in zone II, III, and IV are relatively high. The appearance of NaHCO3 type water in the deeply buried areas is usually related to oil and gas charging. Therefore, within the strata, deeply-buried areas (e.g., zone III), where NaHCO3 type water has been developed, are favorable targets for oil and gas exploration.

Origin and charging histories of diagenetic traps in the Junggar Basin

Oil and gas accumulations in the sandy conglomerate diagenetic traps that developed in the fan delta of the Triassic Baikouquan Formation of the Mahu sag, Junggar Basin, differ from stratigraphic accumulations controlled by sedimentary facies. This study uses conventional gas chromatography–mass spectrometry measurements, mineralogical and petrological data, fluid inclusion analyses, and geophysical inversion to confirm the trap type and accumulation processes. The results indicate that accumulations in the sandy conglomerate formed in distributary channels of the fan-delta front, with the boundary controlled by reservoir quality. In turn, reservoir quality was controlled by differential diagenesis caused by detrital-feldspar content, paleotemperature, and formation fluids, suggesting that the trap is a diagenetic trap. The diagenetic trap formed from secondary pores developed in the fan-delta front facies with seals forming through a combination of altered sandy beds and mudstone. The critical physical property of the reservoir, based on the ratio of its average capillary radius to the ratio of its seal, is a crucial parameter for describing diagenetic trap boundaries. Here, it effectively distinguishes between reservoirs at different burial depths. A good correlation exists between the formation of the diagenetic traps and hydrocarbon filling. Three hydrocarbon charging and two accumulation stages are identified. The diagenetic traps primarily formed in the Jurassic, and the last charging stage of highly mature oil charge occurred in the Early Cretaceous. Few studies have investigated the conglomerate diagenetic trap studied herein, so this study should improve the understanding of oil and gas traps.

The depositional evolution and controlling factors of the Lower Triassic Baikouquan Formation, Northern Mahu Slope, Junggar Basin, NW China

Significant hydrocarbon discoveries that resulted from conglomerate reservoirs in the Baikouquan Formation have been found in the last few years in Mahu Sag, Junggar Basin. Many studies have been conducted to describe the sedimentological complexity of reservoirs. However, few of them have been focused on the depositional characteristics and associated controlling factors in Baikouquan Formation. In this study, analysis of cores, thin sections, wireline logs, and seismic volume were carried out obtain detailed descriptions and interpretations of sedimentary microfacies, depositional evolution, and associated controlling factors. The results indicate that seven sedimentary microfacies are identified in Baikouquan Formation. Furthermore, depositional evolution of fan delta systems from bottom to top of Baikouquan Formation shows retrogradation in general. Tectonic activities along the northwestern fault zone, rising lake levels, arid climate, and high temperature together exert the controls on depositional evolution of fan delta systems in Baikouquan Formation.

Gravel roundness quantitative analysis for sedimentary microfacies of fan delta deposition, Baikouquan Formation, Mahu Depression, Northwestern China

AbstractGravel roundness is one of the simple but crucial parameters in particle shape, which is related to the transportation and deposition of sediments. Based on the digital images of underground drilling cores, this study attempted to characterize and distinguish sedimentary microfacies by quantitatively test gravel roundness trends in the fan delta deposition of the Early Triassic Baikouquan Formation in Mahu Depression, Juggar Basin of China. By the new proposed de-flat roundness measurement, two major parameters are recorded to manifest the rounding degree, which is de-flat roundness value (Rdn) and the corresponding variance value. In the case study, roundness characteristics of four microfacies in the fan delta deposits are displayed and compared. Results show that braided channels and submerged distributary channels are characterized by better rounding (Rdn0.379 to 0.603, and 0.366 to 0.591, respectively) and smaller variance, while debris flow and submerged debris flow are characterized by worse rounding (Rdn0.333 to 0.405 and 0.256 to 0.391, respectively) and larger variance. In vertical of the roundness curves, channels deposits and gravity flow deposits reveal notable distinction in terms of the numeric ranges, fluctuation amplitude, and fluctuate frequency. It is interpreted to represent the different sedimentary processes during particle transport and deposit, as well as new clastics mixed in from other sources. Therefore, roundness could be a useful complementary data to provide quantitative sedimentological evidence and theoretical support for the study of coarse clastic depositional system.

Diagenetic variations with respect to sediment composition and paleo-fluids evolution in conglomerate reservoirs: A case study of the Triassic Baikouquan Formation in Mahu Sag, Junggar Basin, Northwestern China

Understanding reservoir heterogeneity and associated diagenesis, have a paramount importance for efficient petroleum exploration and development strategies. Diagenetic variations and factors that control these processes have, therefore, been investigated in this study using petrographic and geochemical methods, including cathodoluminescence, scanning electron microscopy, x-ray fluorescence, electron probe microanalyses and stable isotope analysis. Mechanical compaction and chemical diagenesis trends have obviously varied as a function of rock types and geological locations. The conglomerate reservoirs with high content of tuffaceous matrix and characterized by poor sorting showed stronger compaction. The tuffaceous matrix displays a large degree of dissolution during the progressive burial diagenesis due to its thermodynamic instability. The tuffaceous matrix in Na-rich conglomerate reservoir rocks mainly transformed into analcite, while it transformed into illite in K-rich conglomerate reservoir rocks. In most conglomerate reservoirs far away from deep-rooted faults, calcite cements are indicated to have been sourced from the decarboxylation of organic matter in the interbedded mudstones. Carbonate cements in conglomerate reservoirs near the deep-rooted faults possibly formed from hydrothermal fluids or thermochemical oxidation of pre-existing methane accumulations. This study can serve us an excellent example for the control of sediment composition and paleo-fluid evolution on diagenetic variations in fan-delta conglomerate reservoirs.

Overpressure origin and its effects on petroleum accumulation in the conglomerate oil province in Mahu Sag, Junggar Basin, NW China

The origin of overpressure and its effect on petroleum accumulation in the large Permian/Triassic conglomerate oil province in the Mahu Sag, Junggar Basin have been investigated based on comprehensive analysis of log curve combinations, loading-unloading curves, sonic velocity-density cross-plot, and porosity comparison data. The study results show that there are two kinds of normal compaction models in the study area, namely, two-stage linear model and exponent model; overpressure in the large conglomerate reservoirs including Lower Triassic Baikouquan Formation and Permian Upper and Lower Wu'erhe Formations is the result of pressure transfer, and the source of overpressure is the overpressure caused by hydrocarbon generation of Permian Fengcheng Formation major source rock. The petroleum migrated through faults under the driving of hydrocarbon generation overpressure into the reservoirs to accumulate, forming the Permian and Triassic overpressure oil and gas reservoirs. The occurrence and distribution of overpressure are controlled by the source rock maturity and strike-slip faults connecting the source rock and conglomerate reservoirs formed from Indosinian Movement to Himalayan Movement. As overpressure is the driving force for petroleum migration in the large Mahu oil province, the formation and distribution of petroleum reservoirs above the source rock in this area may have a close relationship with the occurrence of overpressure.

Diagenesis effects on the conglomerate reservoir quality of the Baikouquan Formation, Junggar Basin, China

Large accumulations of oil and gas have been found in fan delta conglomerate reservoirs in the upper Triassic Baikouquan Formation in the Mahu Sag at the northwestern margin of the Junggar Basin. To effectively explore strongly heterogeneous, high-quality, conglomerate reservoirs, their deposition, diagenesis, and genetic mechanisms must first be thoroughly studied. Analyses of cores, thin sections, fluid inclusions, oxygen isotopes, logging, physical properties data, X-ray diffraction, scanning electron microscopy, and cathodoluminescence confirm that the conglomerates have high feldspar contents as well as volcanic fragments that comprise a variety of micro-lithofacies. The heterogenous reservoir properties include permeability values of less than 1 mD, 1–10 mD, and higher than 10 mD, which correspond to 44.19%, 37.06%, and 18.75% of the reservoir, respectively. The tight reservoirs, mostly developed in the fan delta plain, have experienced extensive compaction and/or calcite cementation and consist of only a few secondary pores. Reservoirs with high porosity and permeability developed in subaqueous channels and experienced relatively weak compaction. These reservoirs contain large numbers of secondary pores that were mainly formed by the dissolution of K-feldspars and volcanic rock fragments. Comprehensive studies of sedimentation and diagenesis in the Baikouquan Formation indicate that these high porosities originated from the chronological coupling of the following three important geological processes: (1) Conglomerate reservoirs with better sorting and roundness and lower mud content are mainly developed in subaqueous distributary channels and have higher porosity and permeability than reservoirs with poorer sorting and roundness. (2) Strong dissolution of K-feldspar and volcanic debris occurred in reservoirs with good original physical properties, forming large numbers of secondary pores. Acidic fluids from source rocks in the Fengcheng Formation led to dissolution. (3) The byproducts of dissolution, which consist mostly of mixed-layer illite/smectite and illite, reduced porosity and permeability. In reservoirs with good original physical properties and fault development, dissolution plays an obvious role in improving physical properties in such relatively open diagenetic systems.

Estimation of oil saturation via pseudo capillary pressure curve from nuclear magnetic resonance log data in tight conglomerate reservoirs

Tight conglomerate reservoirs have complex pore structure and strong heterogeneity which could bring great difficulties in the identification of oil and water layers. In order to solve this problem, the tight conglomerate reservoirs of Triassic Baikouquan Formation and Permian Urho Formation in Mahu Depression, Northwest Junggar Basin in China are selected as the study area. Firstly, 23 representative core plunger samples were selected from 9 wells. The experimental data of helium porosity, permeability, mercury intrusion capillary pressure (MICP) curve, and nuclear magnetic resonance (NMR) T2 spectrum under completely watered condition were measured and analyzed. Secondly, conglomerate reservoir classification criterion was built based on flow zone indicator (FZI). Its classification results conform to the classification of J function and core images. Thirdly, the piecewise power function was adopted to predict the pseudo capillary pressure curve by NMR T2 spectrum and the corresponding models were established via reservoir classification. Fourthly, based on the obtained pseudo capillary pressure curve and average J function curve, a novel method for predicting oil saturation by the ratio of median radius was proposed. Finally, the built models were used to process the experimental data not involved in modeling and log data. The predicting results are well consistent with the experimental results, which indicates the high reliability of the models. The established models are essential for helping the classification of tight conglomerate reservoirs, calculation of reservoir parameters, and identification of oil and water layers.

Seismic sedimentology, facies analyses, and high-quality reservoir predictions in fan deltas: A case study of the Triassic Baikouquan Formation on the western slope of the Mahu Sag in China's Junggar Basin

This study examines problems that are related to large spatial variations in the physical properties of fan-delta sandstone in the Baikouquan Formation on the western slope of the Mahu Sag. This study conducts high-resolution sequence stratigraphy, sedimentary-microfacies identification, seismic-sedimentology analyses, and seismic inversions of high-quality reservoirs by comprehensively utilizing geophysical log data, cores, thin sections, and three-dimensional seismic data. A fourth-order sequence stratigraphic framework of the study area is established through these methods, enabling us to define the sedimentary filling processes that were related to multistage transgression and regression in the Huangyangquan and Xiazijie fan deltas. According to this study's results, the fourth-order sequences SSQ3 and SSQ5 were the development sequences of high-quality reservoirs. Feldspar-dissolution effects produced a secondary porosity-development zone, which favors relatively high-porosity and -permeability physical traps. Sedimentary microfacies, such as distributary and interdistributary channels in the fan-delta plain, alongside subaqueous distributary channels, estuarine mouth bars, and sheet sand in the fan-delta frontal areas, are successfully identified. The results suggest that the fan-delta front is the most favorable subfacies belt for reservoir development in the study area. By using the vertical boundary of the fourth-order sequence stratigraphy and the horizontal boundary of the sedimentary subfacies as the constraint conditions, we perform a facies-controlled seismic impedance inversion, in which the layers are divided to improve the accuracy of the reservoir predictions. Subsequently, five potential regions of high-quality reservoir development are predicted in the fourth-order sequences SSQ3 and SSQ5, and three well positions are proposed. Subsequent exploration drilling achieved industrial oil flow, thereby confirming these predictions from seismic sedimentological analysis.

Utilizing borehole electrical images to evaluate sorting of conglomeratic formation: example from Lower Triassic Baikouquan Formation in Well M152, Mahu Depression, Junggar Basin, China

Grain-size sorting of buried formation in openholes only comes from the particle size analysis of drilled cores. However, cores impossibly cover the whole formation, and the sorting of uncored interval is absent. With ultrahigh-resolution, borehole electrical image contains particular geological attributes, such as grain-sizes, sedimentary structures, and facies. In this paper, a sorting evaluation method is proposed based on conductivity spectrum of borehole electrical image from Baikouquan Formation in Well M152, Mahu Depression. The first stage is revising the depth of the cores by calibrating the cores to the borehole electrical images. The second stage is computing the two-dimensional conductivity spectrum of conductivity image. The third stage is calculating the sorting index from conductivity spectrum. The fourth stage is converting the sorting index to the evaluated sorting by a mathematical equation between sorting index and laboratorial grain-size sorting. In the cored interval of the Well M152, the evaluated sorting is compared with the grain-size of gravels; what can be concluded is that the evaluated sorting values from borehole electrical images gradually reduce with the decrease of the gravelly grain-sizes. The proposed method is demonstrated be beneficial to reflect the vertical diameters and sorting of gravelly grains in deeply buried conglomeratic formation continuously.

Origin and depositional characteristics of supported conglomerates

Abstract The origin and depositional characteristics of supported conglomerates in the Mahu Sag, Junggar Basin, Xinjiang, China, are examined. Based on the terminological comparison, modern sedimentary survey and core description, the initial connotation and similarities and differences in definition between supported conglomerates and other similar concepts are discussed, the modern sedimentary environment in which supported conglomerates develop is analyzed, and the sedimentological characteristics of supported conglomerates formed in different depositional environments revealed by the cores of Mahu conglomerate oil field in the Junggar Basin are described. The supported conglomerate is similar in texture to grain supported conglomerate and openwork conglomerate but has differences from them, so it is suggested to keep the term “supported conglomerate”, but the formation mechanism of supported conglomerate needs to be re-examined. Through field survey of modern sediments in Baiyanghe alluvial fan, Huangyangquan alluvial fan, and Wulungu Lake in Xinjiang, it is found that supported gravels not only formed by flooding events but also by sieving, avalanching, fluvial sorting as well as wind and wave reworking in the depositional environments such as inter-mountain creek, colluvium fan, gravel channel on gobi and the fan surface, lake beach, delta front, subaerial debris flow and subwater grain-flow etc. Supported gravels could form supported conglomerate after being buried. Supported conglomerates of seven different origins have been recognized in the cores of the Triassic and Permian stratum of Mahu Depression, Junggar Basin, namely, supported conglomerates in gravel channel deposits, in wind reworked channel deposits, in gravel beach bar deposits, in wave reworked delta front deposits, in mouth bar deposits and in debris flow deposits respectively. The study shows the supported conglomerates may be formed by a single depositional event or by multi-events during the post-depositional sedimentary reworking and even in diagenesis stage. Through flume experiment, numerical simulation, empirical model and modern sediment survey, infiltration process of gravelly channel can be reconstructed and the primary pore structure of supported gravel can be estimated. Statistics on physical properties of various types of reservoirs in Triassic Baikouquan Formation of Mahu oilfield show that granule conglomerate and pebbly conglomerate have higher porosity and permeability, while the cobble and coarse pebble conglomerate have lower permeability, which indicates that the supported gravels are easy to be reworked by post depositional filtration and diagenesis, and thus decrease in porosity and permeability.

Study on the law of artificial crack propagation and fracturing technology in strong heterogeneous conglomerate strata: a case study of the Mahu glutenite in Xinjiang Oilfield

The glutenite reservoir of the Triassic Baikouquan Formation in the Mahu sag with a large amount of resources, is the main block for Xinjiang oilfields and even domestic oil production in recent years. The reservoir is characterized by deeper burial, fewer natural cracks, low fluidity, high pressure coefficient, high horizontal stress difference and special lithology. For these geological problems, researches on fracture extension law, proppant placement law and fracturing technology have been developed to form an integrated volume fracturing technology of heterogeneous glutenite geological engineering. The contributions are as follows:(1) The lithofacies reservoir in Mahu includes matrix support, particle support and mixed support, which makes the conglomerate reservoir have large differences in many respects. The mechanical parameters of granular-supported conglomerate are higher than those of complex-base-supported conglomerate, and the brittleness index is higher.(2) Fracture regularity of glutenite varies greatly at different scales. As the ratio of fracture size to gravel size enlarges gradually, the influence of gravel on fracture extension weakens.(3) The fracture roughness of glutenite has great influence on fluid flow and proppant migration. The sand-laden fluid flows by fingering in small fracture. The crack with larger width is the dominant flow channel and will influence proppant placement.

Study on the dosage of temporary plugging Agent for steering fracturing

The Triassic Baikouquan Formation in the Junggar Basin has developed a large number of dense sandstore conglomerate reservoirs, which belong to ultra-low permeability and ultra-low permeability refractory reservoirs. In recent years, the productivity of single well is improved by selecting potential production wells for multi-stage steering fracturing. In order to realize the forced steering of fractures, it is very important to study the sealing pressure of temporary plugging agent. According to the actual needs of Baikouquan steering fracture, the net pressure model of steering fracture is established. The net pressure value in the seam is calculated according to the change of ground stress after steering, then calculated the minimum temporary plugging agent sealing pressure needed for a single fracture. Based on the net pressure model, the corresponding software is developed and applied to the field. The practical application effect is good, which provides economical and effective technical technical support for the continuous and stable production of low permeability oil field.

Controls on reservoir quality in fan-deltaic conglomerates: Insight from the Lower Triassic Baikouquan Formation, Junggar Basin, China

Abstract Fan delta sandy conglomerates form important oil and gas reservoirs. Recently, a new giant oilfield was discovered in the Lower Triassic Baikouquan Formation (T1b) in the Mahu Sag of the Junggar Basin, northwestern China. However, the fan delta sandy conglomerate reservoirs are strongly heterogeneous. Most have poor permeability and host little hydrocarbons, while a subset at the delta front exhibit high porosity and permeability, forming high-quality reservoirs. To explain this disparity, the sedimentary facies, diagenesis, and reservoir quality of the sandy conglomerate strata, and their interactions, were studied. Detailed logging of 253m cores indicates that the T1b was deposited in a lacustrine fan delta complex, comprising ten lithofacies from coarse matrix-supported pebbly conglomerate (Gm) to fine massive mudstone (Fm) in four Facies Associations. Interpretation of optical microscope, backscattered and scanning electron microscope imaging show that these ten lithofacies underwent differential diagenesis, especially dissolution of minerals such as orthoclase. Dissolution was particularly prevalent in the subaqueous distributary channel deposits of sandstones (St), hyperpycnal-flow massive sandstones (Sm) and grain-flow deposits of sandy gravelly conglomerates (Gcs) at the delta-front, forming abundant secondary pores. These pores enhanced the reservoir performance and led to high porosity and permeability within these three lithofacies. For these reservoirs, continuous winnowing at the delta front led to relatively high primary porosities, and subsequent mineral dissolution during burial diagenesis, closely related to acidic Mn-rich hydrocarbon-bearing fluids, significantly improved the porosities further. Migration of hydrocarbon-bearing fluids was facilitated by faults cutting through the reservoir and underlying source rocks. This led to the development of belts of high-quality reservoir at the delta front near the fault conduits. This model for reservoir development and charge suggests that further reservoirs can be expected within the T1b of the Mahu Sag.

Microfacies characteristics and reservoir potential of Triassic Baikouquan Formation, northern Mahu Sag, Junggar Basin, NW China

By using data such as lithology, thin sections, sedimentary structure, particle size, logging facies signs, mercury intrusion, porosity and permeability from 34 wells, 11 types of sedimentary microfacies were divided in this study. Upon analysis, sedimentary microfacies exert significant control on reservoirs, and high quality reservoirs are primarily developed with the following sedimentary microfacies: gray sandy conglomerate in underwater distributary channels microfacies of fan delta fronts sub-facies, river-estuary dams and gray sandstones of distal bars on the front edge of the fan delta that have strong hydrodynamic conditions and good stability. Relatively good reservoirs are primarily distributed in the braided channel in fan-delta plains with brown sandy conglomerates, main channel of underwater distributary channels on the front edge of the fan delta with gray conglomerates and underwater distributary channel ends on the front edge of the fan delta with gray fine sandstones. With the stable tectonic background, Triassic sedimentary microfacies in the Mahu sag control the distribution and development of reservoirs. Therefore, sites of high quality reservoirs can be predicted by sedimentary microfacies, and this study provides guidance for oil and gas exploration.

Controls of paleo-overpressure, faults and sedimentary facies on the distribution of the high pressure and high production oil pools in the lower Triassic Baikouquan Formation of the Mahu Sag, Junggar Basin, China

Large quantities of high-pressure oil pools have been discovered in the glutenite reservoirs with low porosity and low permeability in the Lower Triassic Baikouquan Formation of Mahu sag, Junggar Basin. Overpressure has a close relationship with the generation of high-production oil pools in the Baikouquan Formation. In areas with abnormally high overpressure, the daily oil and gas production of single wells is high. Geological and geophysical analysis, and two-dimensional (2D) basin models have been used to explain the mechanisms of overpressure in the Baikouquan Formation and to establish a hydrocarbon accumulation model of high pressure and high production oil pools. Based on the hydrocarbon accumulation model, the main controlling factors of high pressure and high production oil pools generation have been summarized, and the favorable accumulation zones have been predicted. The results show that the chief reasons for overpressure are disequilibrium compaction and the pressure conducted through faults. In the hydrocarbon accumulation model of high pressure and high production oil pools, the overpressure compels faults that connect source rocks with reservoirs to open and become the valid conductive systems, and the oil-bearing overpressure fluid charges into the Baikouquan Formation along faults and forms high pressure oil pools in the frontier facies glutenite reservoirs near the faults. The main controlling factors of oil accumulation are the paleo-overpressure of Fengcheng Formation source rock during the main hydrocarbon migration stage (the Early Cretaceous, before 146 Ma), the faults on the ancient nose-like belts of structural uplifts and the fan-delta frontier facies glutenite reservoirs in the Baikouquan Formation. According to the accumulation model, the fan-delta frontier facies glutenite reservoirs of the Baikouquan Formation can be divided into three sections based on the favorability of oil accumulation I, II and III, from good to bad.

Petrology Characters of Conglomerates in Baikouquan Formation, Mahu Sag, Junggar Basin

Mahu Sag, one of the most oil and gas bearing sags in Junggar basin, is in the northwestern margin of the basin. On gentle slope region of the sag, a serial of large scale coarse fan delta deposits were developed in Triassic Baikouquan Formation. In order to understand the petrology characters of conglomerates in Baikouquan Formation, based on lots of cores, grain size analysis, normal thin sections, casting thin sections, scanning electron photomicrographs, mineral composition identifications, clay mineral and bulk composition identifications of X-ray diffraction, were comparatively studied for Xiazijie and Huangyangquan fan-delta in Mahu Sag. Mineral composition of conglomerates is main tuff, while eurite, dacite, rhyolite, andesite and granite are common. However, more tuff and granite, less eurite and andesite in Xiazijie fan-delta, there is no rhyolite in Huangyangquan fan-delta. Kaolinization and chloritization of conglomerates are ubiquitous in the formation. The content of chlorite and kaolinite is higher in Xiazijie fan-delta, with lower illite-smectite and illite. There is less feldspar of clastic and more calcite of cement in Xiazijie fan-delta.