Kuqa Depression Research Articles

Cenozoic multi-phase intracontinental deformation of the Tianshan Range (NW China): Constraints from detrital zircon provenance and syn-tectonic sedimentation of the Kuqa Depression

Influenced by the far-field effect of the India–Eurasia collision during the Cenozoic, both the Tianshan Range and Kuqa Depression underwent multi-phases of intracontinental tectonic activation. The extremely thick Cenozoic sediments in the Kuqa Depression recorded the basin-mountain coupling process of the South Tianshan and Kuqa Depression. In this study, detailed structural investigations, stratigraphic analysis, and detrital zircon U–Pb dating of the Cenozoic sediments were conducted in the Kuqa Depression to reconstruct the Cenozoic uplift history of the South Tianshan Range. U–Pb ages of detrital zircon from sandstones show four age peaks that correspond to four significant provenance changes in the Kuqa Depression. These four periods of changes occurred at the Cretaceous–Early Cenozoic, Late Eocene–Oligocene, Early Miocene–Middle Miocene, and Early Pliocene–Early Pleistocene. These changes in provenance reflect variations in tectonic activation and paleogeographic settings in the Kuqa Depression–Tianshan Range. Combined with the syn-tectonic growth strata and previously published magnetostratigraphy and low-temperature thermochronology data, we therefore argue that significant Cenozoic deformation and uplift of the Tianshan Range was initiated at the Early Eocene (50–46 Ma), strengthening in the Late Eocene(∼36 Ma), becoming more evident and extending to the entire Tianshan and Basin–Range boundary during the Middle Miocene (13–10 Ma), and culminating and extending to the southern Kuqa Depression since the Early Pliocene (∼6.5 Ma), thus suggesting the continuous convergence of the on-going India–Eurasia collision in the Cenozoic.

Structural diagenesis in ultra-deep tight sandstones in the Kuqa Depression, Tarim Basin, China

Abstract. The Lower Cretaceous Bashijiqike Formation of the Kuqa Depression is made up of ultra-deeply buried sandstones in fold-and-thrust belts. Few researches have linked diagenetic processes with structure. To fill this gap, a comprehensive analysis integrating diagenesis with structure pattern, fracture and in situ stress is performed following a structural diagenetic approach. The results show that the pore spaces include residual intergranular pores, intergranular and intragranular dissolution pores, and micro-fractures. The sandstones experienced a high degree of mechanical compaction, but compaction is limited in well-sorted rocks or abundant in rigid quartz grains. The most volumetrically important diagenetic minerals are calcites. The framework grains experienced a varied degree of dissolution, and intergranular and intragranular dissolution pores are formed. Special attention is paid on the dissolution associated with the fracture planes. Large numbers of natural fractures are cemented by carbonate cements, which limit fluid flow. In addition, the presence of fracture enhances dissolution and the fracture planes are enlarged by dissolution. Cementation and dissolution can occur simultaneously in fracture surfaces, and the enlarged fracture surfaces can be cemented by late-stage cements. The in situ stress magnitudes are calculated using well logs. The horizontal stress difference (Δσ) determines the degree of mechanical compaction, and rocks associated with low Δσ experienced a low degree of compaction, and these contain preserved intergranular pores. Natural fractures are mainly related to the low Δσ layers. The presence of intergranular and intragranular dissolution pores is mainly associated with the fractured zones. The high-quality reservoirs with intergranular pores or fractures are related to low Δσ layers. The structural diagenesis researches above help the prediction of reservoir quality in ultra-deep sandstones and reduce the uncertainty in deep natural gas exploration in the Kuqa Depression.

Hydrocarbon Accumulation Model Controlled by Overpressure Evolution in the Kelasu Thrust Belt of the Kuqa Depression, NW China

Abstract The Kuqa Depression is the most representative overpressured hydrocarbon accumulation area in western China. The early rapid subsidence since 5 Ma and the strong uplift in the late period have led to a complicated evolution history of the overpressure. Three hydrocarbon charging episodes of Cretaceous in Kuqa Depression were identified based on petrography, microthermometry of fluid inclusions, and fluorescence spectroscopy characteristics. Low-maturity oil, represented by hydrocarbon inclusions with yellow-green-yellow fluorescence, entered the reservoir at circa 5-3 Ma, whereas high-maturity hydrocarbons, as indicated by hydrocarbon inclusions with blue-green-blue fluorescence, charged the reservoir at circa 3-1.2 Ma. Pure gas inclusions with nonfluorescence represented one episode of gas charging from approximately 1.2 Ma to the present. By applying the PVTX simulation method of inclusions, the paleo-pressure evolution of formations was reconstructed, that is, the three-stage model of pressurization-release-pressurization. The coupling relationship between the paleo-pressure evolution of formations and the history of hydrocarbon charging at different stages was reconstructed. This conformed to a compound overpressure-controlled hydrocarbon accumulation model with oil convergence in the early period, oil adjustment along the fracture in the middle period, and rapid gas charging in the late period.

Geological and Geochemical Characteristics of the Terrestrial Lower Jurassic Shale in Tarim Basin and its Favorable Exploration Areas

Large amounts of conventional gas resources that originated from terrestrial Lower Jurassic shale were discovered in the Tarim Basin, indicating promising exploration prospects for shale gas resources, whereas limited understandings were obtained on the geological and geochemical characteristics of the Lower Jurassic shale. In this study, based on cores of exploration wells and field outcrops, total organic carbon (TOC) pyrolysis, microscopic composition, organic elements, vitrinite reflectance, x-ray diffraction, and methane isothermal adsorption experiments were carried out on Lower Jurassic shale in the Tarim Basin. The results show that the TOC content of shale is relatively high, but the TOC content of shale in different regions is quite different. Among them, the Kuqa Depression is the highest (more than 3%), the Southwest Tarim Basin is second (more than 1%), and the East Tarim Basin is the lowest. The main types of kerogen in shale are mainly type III and type II2. The thermal evolution maturity of shale in different regions is quite different; the highest Ro of shale in the Southwest Tarim Basin is more than 2.0% and that of shale in the Kuqa depression is higher than 1.5%, both of which have entered the stage of high-over-mature evolution, and the shale in the East Tarim Basin is only in the low maturity–mature stage. The overall content of brittle minerals such as quartz in shale is greater than 40%, which has good fracturing properties. The adsorbed gas content of shale is high, but there is a great difference (0.5–4 m3/t), which is related to the large difference in the abundance of organic matter, thermal maturity, and clay mineral content of shale. Therefore, the Lower Jurassic shale gas in the Tarim Basin has good prospects for exploration. Based on the superposition method of the main controlling geological factors, it is predicted that the favorable areas for shale gas exploration are mainly located in the Keshen and Yinan-Yeyun areas of the Kuqa Depression and the Caohu Sag-Mandong area of the East Tarim Basin. This research not only provides basic data for the evaluation of shale gas resources in our country, but also provides certain guidance for the exploration of Lower Jurassic shale gas in the Tarim Basin.

Fracture effectiveness evaluation in ultra-deep reservoirs based on geomechanical method, Kuqa Depression, Tarim Basin, NW China

Onshore ultra-deep oil and gas resource is abundant, which has become the main area for exploration and development in the future. Fracture is an important factor affecting the development of ultra-deep reservoir, and its effectiveness, as a significant parameter for quantitative evaluation of the reservoir, determines the production. Taking the DB-4 ultra-deep gas reservoir in Kuqa Depression as an example, through geomechanical methods, the in situ stress distribution of the wellbore is determined by using drilling data and logging data. Based on the identification and quantitative characterization of fracture parameters, the stress state and shear slip trend of fractures are analyzed by three-dimensional Mohr's circle analysis technique and Mohr Coulomb criterion, so as to quantitatively evaluate the effectiveness of ultra-deep fractures. Based on above analysis, the fracture opening under the condition of fluid injection is simulated to establish the relationship between fracture effectiveness and oil and gas production capacity. The results show that the gas reservoir where Well X4 of DB-4 gas reservoir has a burial depth of more than 8,000m, a typical onshore ultra-deep gas reservoir, and it is in an environment with extreme strong in situ stress. For the Cretaceous target reservoir, the horizontal minimum principal stress ranges between 165–180 MPa and the horizontal maximum principal stress generally exceeds 200 MPa. Natural fractures of Well X4 are largely developed, and the wellbore fracture parameters show strong heterogeneity. The Well X4 has low fracture opening pressure and high fracture effectiveness on the whole. The production capacity of gas wells in the ultra-deep reservoir shows extremely obvious positively correlation with the effectiveness of fractures under the influence of in situ stress, while it has little influence on petrophysical properties such as porosity and reservoir thickness. Both the fracture effectiveness evaluation method and results of DB-4 ultra-deep gas reservoir is helpful to provide geological reference for the efficient development of ultra-deep oil and gas resources in Kuqa Depression, and it is of significance for similar ultra-deep fractured reservoirs in the world.

Microscopic Seepage Mechanism of Gas and Water in Ultra-Deep Fractured Sandstone Gas Reservoirs of Low Porosity: A Case Study of Keshen Gas Field in Kuqa Depression of Tarim Basin, China

To study the microscopic seepage mechanism of gas and water in fractured sandstone gas reservoirs of low porosity, this kind of reservoir in the Keshen gas field, Kuqa depression of Tarim basin in China, was taken as an example. Based on rock samples and microscopic visualization technology, nuclear magnetic resonance experiments of saturated water–gas drive and CT scanning experiments of saturated gas–water drive were conducted. The seepage mechanism of water invasion during the gas development were simulated. Subsequently, the distribution of irreducible water saturation and the influence factors on the efficiency of drive were analyzed. The results show that the distribution of gas and water is mainly related to structures of matrix pores, fracture development pattern, and density. The main factors resulting into good reservoirs include large matrix pores and high angle fractures, low irreducible water saturation, and high separation between gas and water. The efficiency of water drive is positively correlated with fracture porosity and dip angle. High angle fractures can effectively improve the seepage capability and then increase the efficiency of water drive. Besides, the great proportion of large pore size in matrix, high fracture dip, porosity, and density can also improve the efficiency of water drive. Therefore, for the development of fractured sandstone gas reservoirs of low porosity, the study of matrix pores and fractures is quite important since it can provide guidance for the efficient deployment of wells. The increase of fracture density is significant by large-scale sand fracturing in order to improve the efficiency of water drive. It is necessary to strictly control the gas production rate of the gas reservoir and delay the water invasion rate as far as possible. In case of serious waterlogging, shut-in all wells in gas reservoirs is a choice to strengthen the gas–water imbibition between fractures and matrix, which can improve the recovery of the gas reservoir.

Reservoir Characteristics of Tight Sandstone and Sweet Spot Prediction of Dibei Gas Field in Eastern Kuqa Depression, Northwest China

Great progress has been made in the exploration of tight sandstone gas resources in Kuqa depression. Great progress has been made in Dibei structural belt, which proves the previously unproven favorable area for tight sandstone gas. The physical properties, controlling factors, and characteristics of tight sandstone from the Ahe (J1a) Formation in the Dibei gas reservoir are analyzed. The results show that the tight sandstone of the J1a Formation is mainly feldspar lithic sandstone, with low porosity (average 9.1%) and low permeability (average 0.09 mD). Compaction (average compaction rate 61.9%) reduces porosity more than cementation (average cementation rate 14.3%). Secondary dissolution pores (average thin section porosity is 3.4%) dominate. The homogenization temperature has two peaks; the first peak is 85–110 °C, and the other peak is 115–140 °C, indicating that oil and gas experienced two filling stages at 12 Ma and 4.5 Ma, respectively. Eodiagenesis, A substage of mesogenetic diagenesis, and B substage of mesogenetic diagenesis happened in the area. Tight sandstone is developed in the B substage of mesogenetic diagenesis. The main controlling factors of diagenesis are: strong dissolution and structural pore increase; oil and gas charging and overpressure. The reservoir forming mode of the Dibei gas reservoir is: crude oil filling in the Late Neogene (12 Ma); reservoir densification in the late deposition of Kangcun Formation (7 Ma), mature natural gas filling in the early deposition of Kuqa Formation (4.5 Ma), and gas reservoir formed after transformation and adjustment in the deposition period of Quaternary (2 Ma). According to this model, it is predicted that the favorable area of the Dibei gas reservoir is in the southeast of the Yinan 2 well. This study provides guidance for the study of tight sandstone gas in other areas of the Kuqa Depression.

Control of the Cretaceous Paleofluid Potential on the Source-Distal Lithologic Reservoirs in the Western Tabei Area of the Tarim Basin

The Cretaceous clastic oil and gas reservoirs in the western Tabei area of the Tarim Basin are far away from source rocks (source-distal), and the hydrocarbons mainly originate from Triassic continental source rocks in the northern Kuqa Depression. Early exploration focused on structural oil and gas reservoirs, and yet, with deepening of exploration practice, exploration has shifted from structural oil and gas reservoirs to lithologic reservoirs. In such context, under guidance of the theory of migration and accumulation for source-distal reservoirs, the key accumulation period of Triassic source rocks is determined, and the migration path of oil and gas is clarified. According to the geological characteristics of the study area, the impression method and sequence ratio method are used to restore the paleoburial depth, and the Fillippone formula is used to restore the paleopressure. Based on Hubbert’s theory, the paleofluid potential field of Triassic oil and gas in the Neogene Kangcun period is reasonably reconstructed. These combined with the planar structural evolution of Cretaceous reveal the preferential source-distal migration paths and directions of oil and gas. The favorable area of oil and gas accumulation is demarcated, and then, the facies belts with favorable lithology have been identified. The research results show the following: (1) The hydrocarbons of the Cretaceous oil and gas reservoirs originate from the Triassic source rocks. The Neogene Kangcun period is the key accumulation period. Hydrocarbons migrate to the western Tabei area along the Cretaceous basal unconformities and Late Yanshanian faults. (2) The paleofluid potential field of the Cretaceous during the key accumulation period shows the characteristics of “being high in the north and low in the south,” which is consistent with the gradual decrease of fluid potential along the migration distance from the northern hydrocarbon generation center (Kuqa Depression) to the south slope, and coincides with the main distribution range of source rocks in the Kuqa Depression. On the basis of the aforementioned, four preferential source-distal migration paths and directions of hydrocarbons have been clarified, and the Yudong-Yingmaili area is confirmed as a favorable area for the source-distal migration and accumulation of hydrocarbons into the Cretaceous. (3) In terms of the favorable areas for source-distal oil and gas migration and accumulation to Cretaceous strata, the forward distal end and lateral flanks of the branched retrogradational delta are the favorable facies belts for the next exploration of lithologic oil and gas resources. The recent breakthroughs in the lithologic reservoirs of wells D7 and M46 have confirmed that the findings of this research on the preferential source-distal migration paths and accumulation positions of hydrocarbons are of great guiding values for exploration deployment of Cretaceous lithologic reservoirs far away from source rocks.

Effects and practical applications of present-day in-situ stress on reservoir quality in ultra-deep layers of Kuqa Depression, Tarim Basin, China

There is a significant relationship between in-situ stress and reservoir quality, to reinvent the theoretical understanding and technical methods of reservoir evaluation from the perspective of in-situ stress. Based on rock mechanical test and logging data, combined with regional evolution and structural deformation, this study carried out systematic geomechanics research, proposing the quantitative characterization of stress concentration parameters to realize the optimization of favorable zones. The results show that in-situ stress and fracture permeability under its control are important factors in determining the productivity in the ultra-deep reservoir. It is preferable to choose a location with low stress and good fracture activity, rather than an adverse location such as a local stress concentration area characterized by frequent borehole breakouts. The imbalance between in-situ stress and rock strength causes high stress. Moreover, the accuracy of reservoir classification is improved by incorporating the relevant parameters under the influence of in-situ stress into the evaluation method of reservoir quality. It is vital to fully utilize the multiple advantages of highly deviated wells with various favorable areas and multiple vertical fractures to address complex problems and improve the efficiency of exploration and development.

3D Geomechanical Modeling and Prediction of Fractures in the Bozi Ultra-Deep Gas Field in the Kuqa Depression of Tarim Basin

In order to clarify the fracture distribution characteristics of the Bozi gas field in the Kuqa Depression, based on the statistics of fracture parameters from core data and imaging logging, the three-dimensional (3D) structural model of the complex thrust structure is established by using the voxel-based morphometry (VBM) structural framework modeling technology; the 3D heterogeneous rock mechanics field in the study area is constructed by well-to-seismic integration. The relationship between in situ stress field and fracture parameters is established under the consideration of rock fracture criterion, and fracture prediction of the Cretaceous reservoir in the Bozi gas field is carried out with the finite element numerical simulation method. Considering the influence of in situ stress field on fracture parameters, fracture activity is analyzed. The results show that the Cretaceous reservoirs in the Bozi gas field generally develop fractures, most of which are high-angle shear fractures of tectonic origin and are semi-filled or unfilled. The fracture distribution of the Bozi gas field is obviously controlled by local structures such as folds and faults. From north to south, the fracture development gradually weakens, and the fracture density of Bozi 104 and Bozi 102 fault blocks in the north is the highest. The fracture in the northern fault block of the Bozi gas field shows high activity, while that in the southern fault block shows low activity. The fractures in the higher structural parts of most fault blocks show high activity.

E/I-corrected inclination shallowing in Cenozoic redbeds from the northern Tarim Basin, NW China: Possible causes and paleogeographic implications

AbstractBecause of their widespread occurrence and ability to carry stable remanence, continental redbeds in central Asia are frequently used in paleomagnetic studies. However, the paleomagnetic inclinations recorded by redbeds are much shallower than the expected values, as redbeds are usually subjected to inclination shallowing. To recognize and correct the inclinations recorded by the Cenozoic redbeds, the paleomagnetic data that were used for magnetostratigraphic studies in the Kuqa Depression, northern Tarim Basin, are reanalyzed in this study. The mean inclinations of the four groups of samples (Eocene, Oligocene, Miocene, and Pliocene) are systematically ~20° shallower than the expected values calculated from the apparent polar wander paths (APWPs) of Eurasia, indicating the presence of inclination shallowing. We apply the elongation/inclination (E/I) method to correct the inclination shallowing. The mean inclinations of the Eocene, Oligocene, Miocene, and Pliocene sediments are corrected from 40.5° to 63.1°, 41.0° to 63.8°, 42.0° to 63.8°, and 44.7° to 63.2°, within 95% confidence limits between 55.1° and 71.6°, 53.7° and 70.4°, 51.5° and 72.7°, and 52.2° and 71.3°, respectively, which are indistinguishable from the expected inclination values. Our results suggest that inclination shallowing in the redbeds of central Asia can be reasonably corrected using the E/I method, and sedimentary processes such as compaction and/or imbrication in the very early stage of burial are important causes for inclination shallowing. Paleolatitudes calculated from the E/I-corrected inclinations show that the Tarim Basin should have reached or been at least close to its current latitude since the Cretaceous. The Cenozoic crustal shortening estimate of the northern Tarim Basin is not detectible for paleomagnetic study.

Study on Sedimentary Facies and Reservoir Characteristics of Paleogene Sandstone in Yingmaili Block, Tarim Basin

Block Yingmai 7 is structurally located in the western segment of the southern margin of the Kuqa Depression in the Tarim Basin. In the foreland basin, huge continental Mesozoic and Cenozoic strata have been deposited. In recent years, the Paleogene bottom sandstone section has been the main oil and gas exploration horizon. In order to further improve the oil and gas exploration effect of the Paleogene bottom sandstone in the study area and improve the accuracy of reservoir prediction, based on the related theory of sedimentology and petrology, this paper analyzes and studies the cores obtained by drilling in the Paleogene through laboratory core analysis experiments. The study shows that the Paleogene bottom sandstone is a braided river delta sedimentary system, and the sedimentary microfacies are mainly underwater distributary channels. The sandstone type is mainly light gray lithic feldspar fine sandstone, the sandstone debris particle sorting degree is medium-good, and the roundness is sub-edge-sub-circular. The microscopic characteristics of the reservoir are large pore throat radius, low displacement pressure, mainly intergranular pores, and good pore connectivity. It is a thin-layered mesoporous, medium-permeable, large-throat, and strongly heterogeneous reservoir. Finally, a classification evaluation table of reservoirs in block Yingmai 7 is established, and it is considered that the reservoirs of types I and II are enriched areas of oil and gas resources. The research results provide evidence for the prediction of oil and gas reservoirs.

Logging identification for diagenetic facies of tight sandstone reservoirs: A case study in the Lower Jurassic Ahe Formation, Kuqa Depression of Tarim Basin

The Ahe Formation is one of the significant hydrocarbon units in the Kuqa Depression of Tarim Basin, which is characterized by poor reservoir quality and strong heterogeneities due to the diagenetic effects. Thus, ‘diagenetic facies’ are introduced to explore high-quality reservoir layers. According to the reservoir spaces, main diagenetic minerals and diagenesis, four types of diagenetic facies are categorized: tightly compacted facies, dissolution facies, carbonated cemented facies and microfracture facies. Petrophysical characteristics of different diagenetic facies are summarized, which shows that the dissolution facies and microfracture facies have higher porosities, permeabilities and bigger pore radii. Logging characteristics indicate that logging values of four diagenetic facies are overlapped seriously, making it impossible to classify them by original logging crossplot. Principal component analysis (PCA), linear discriminant analysis (LDA) and back propagation neural networks (BPNN) are used to build diagenetic facies identification models, and the former two belong to the linear statistical algorithms, while the latter is a nonlinear algorithm. By comparing the identification accuracy of these three algorithms, principal components (PCs) crossplot cannot recognize diagenetic facies effectively. LDA can achieve automatic identification by establishing discriminant functions, but its identification accuracy (71.7%) is too low to satisfy the exploration requirements. However, the trained BPNN yield 80% accuracy, which is more advantageous than PCA and LDA. The blind test shows that the predicted results by trained BPNN have a very high coincidence with the thin section analysis and the logging interpretation results. Therefore, the BPNN as provided in this paper can be effectively used for diagenetic facies identification based on conventional well logs.

Palaeogeographic reconstructions of the Eocene-Oligocene Tarim Basin (NW China): Sedimentary response to late Eocene sea retreat

The Paleogene sedimentary successions of the Tarim Basin of western China document a major regression of the proto-Paratethys Sea, significantly changing the land-sea distribution and thereby the palaeoclimatic conditions in Central Asia. However, a comprehensive reconstruction of the palaeogeographic evolution of the basin is lacking because only few exposures are known from the central part of the basin that is mostly covered by the Taklamakan Desert. Here, we reconstruct the main palaeoenvironmental changes following Eocene sea retreat by determining the sedimentological facies of 69 wells that are internally correlated by using seismic profiles and externally to published sections of the exposed southwestern and northern margins of the Tarim Basin. Two major depocentres existed in the Southwest Foredeep and the Kuqa Depression, separated from each other by the Bachu Uplift that was most likely not a particularly high terrain during the Paleogene. We confirm that a major transition from marine to continental-lacustrine sedimentation took place during the Eocene-Oligocene transition in the central parts of the Tarim Basin. We provide new palaeogeographic maps with Eocene and Oligocene facies distributions in the Tarim Basin, which will facilitate a better understanding of the sedimentary response to Paleogene sea-level change and tectonic events of the neighboring mountain ranges. Our reconstruction confirms that both tectonic and eustatic forcing played an active role in controlling the late Paleogene transgression-regression in the Tarim Basin. Provenance and palaeocurrent analyses, combined with sediment distribution patterns, indicate gradual growth and continuous uplift of the Tibetan Plateau following India–Asia collision in the early Paleogene. The demise of the Tarim Sea at ~41 Ma correlates with palaeoclimatic and environmental changes observed in several basin of central Asia. After sea retreat, the Tarim region progressively transformed into a large and shallow lake system that potentially persisted up to the (early) Oligocene. • Sedimentary facies of 69 drill holes from the Tarim Basin of SW China are analysed. • Palaeogeographic reconstructions are based on Eocene-Oligocene facies distribution. • Facies patterns indicate late Eocene tectonic activity of the Pamir and West Kunlun. • Early Bartonian sea retreating from Tarim relates in time to inner Asian aridification. • During the early Oligocene a large lake persisted in the Tarim Basin.

Characteristics of Pore-Throat in Tight Sandstones of the Jurassic Ahe Formation in the Northern Tarim Basin

In order to clarify the characteristics of pore-throat in tight sandstone reservoirs in the Dibei area of the Kuqa Depression in the Tarim Basin (Northwest China) and to make clear its impact on reservoir quality and productivity, microscopic observation and quantitative analysis of 310 tight sandstones in the Kuqa Depression are carried out by using various methods. Microscopic observation shows that the shapes of the pores are flat, oval, and long-narrow. A great number of throats connect the nanoscale pores in the form of a network. Quantitative analyses including RCMP (rate-controlled mercury penetration), HPMI (high-pressure mercury injection), NA (nitrogen adsorption), and routine and stress-dependent core analysis show that the peak of pores radius ranges from 125 μm to 150 μm, and the throat radius is in the range of 1 μm-4 μm. The throat space accounts for about 2/3 of the total space of the tight sandstones, which is the major storage space for natural gas. The space shape has a great influence on the reservoir seepage capacity, particularly under the condition of overburden pressure. The pores with throat radius greater than 300 nm have free fluid, and they contribute more than 98% of the reservoir permeability. The pore spaces with throat radius among 300 nm-52 nm can release fluids by reservoir stimulation. The pore-throats with radius < 52 nm cannot release the irreducible hydrocarbon fluids. In addition, formation pressure is easy to destroy tight sandstone reservoir. The research results will provide insights into the efficient recovery of natural gas in tight sandstones.

Pore structure evaluation in ultra-deep tight sandstones using NMR measurements and fractal analysis

The reservoir quality, pore spaces and pore size distributions of Bashijiqike sandstones in Kuqa depression were described by thin sections, SEM (scanning electron microscopy) analysis and nuclear magnetic resonance (NMR) tests. In order to quantitatively characterize the complexity of pore structure, NMR T2 (transverse relaxation time) spectrum was used for fractal analysis. This study unravels the relationships between petrophysical parameters, NMR parameters and fractal dimension of the ultra-deep tight sandstones. Primary intergranular pores are the main component of pore spaces, followed by secondary dissolution pores and micropores, and there contain microfractures. The NMR T2 spectra are either bi-modal or uni-modal distribution. The uni-modal T2 spectrum reflects uniform pore spaces. The coexistence of intragranular pores and intergranular pores leads to the bi-modal T2 spectrum. There is a positive correlation between fractal dimensions and T2gm (geometric mean of the T2 distribution). Consequently, four pore structure types are determined according to irreducible water content, T2gm, RQI (reservoir quality index), and the characteristics of individual pore structure are summarized. Because of the uniform pore space, Type I and Type IV have the lowest fractal dimensions. The structure of Type II and Type III are most heterogeneous due to their combination of intergranular and intragranular pores. The results help clarify the internal relationships between petrophysical parameters and microstructure, and have implications for pore structure evaluation of ultra-deep sandstones worldwide.

Characteristics of hydrocarbon migration and accumulation in the Lower Jurassic reservoirs in the Tugerming area of the eastern Kuqa Depression, Tarim Basin

The hydrocarbon migration and accumulation process in the Kuqa Depression are complex. In recent years, the Jurassic strata have recorded hydrocarbon discoveries in the Tugerming area of the eastern Kuqa Depression. However, it is a new exploration area, and the characteristics of hydrocarbon accumulation are unclear, restricting oil and gas exploration and development. In our study, the deeply-buried and shallow-buried Jurassic strata in the Tugerming area are the research objects. Quantitative fluorescence technique and the observation of fluid inclusions are implemented on the selected samples of Jurassic reservoirs to determine the stages and times of hydrocarbon charging. Gas chromatography-mass spectrometry analysis for saturated hydrocarbons is used to identify the origin of organic matter in oils. Combined analytical data with the reconstructed histories of burial, thermal evolution and tectonic evolution, allow simulating the hydrocarbon migration and accumulation process in the Tugerming area. The results show that two categories of hydrocarbon accumulation mechanisms (Burnham and Sweeney, 1989). The first type is acted as the type of “self-generation and self-storage and late accumulation”. Three stages of hydrocarbon charging have occurred in the deeply-buried Lower Jurassic reservoirs, represented by two wells (Tudong 2 and Tuge 4). The charging time is the early-middle stage of Miocene Kangcun Formation (18–9 Ma), forming the yellow or yellow-green fluorescent oil inclusions and paleo-oil reservoir. During the sedimentary period of the late Kangcun Formation to the early Kuqa Formation (9–5 Ma), the reservoir experienced massive condensate oil migration, corresponding to blue-white fluorescent oil inclusions. Large-scale natural gas was expelled into the reservoirs since the deposition stage of Kuqa Formation (5–0 Ma), and then accumulated in the trap controlled by the late Himalayan movement, forming the current gas reservoir. Moreover, the hydrocarbons are generated from Jurassic coal measure source rocks in the Well Tudong 2 based on the characteristics of biomarkers (Burruss et al., 1991). The second type is characterized by “lower source rock and upper reservoir and accumulation in the late or recent period”, developed in the shallow-buried Lower Jurassic reservoirs containing two wells (Tuxi 1 and Mingnan 1). In this case, there are two stages of crude oil charging: mature oil charging in the early-medium Miocene (18–12 Ma) and condensate oil migration in the late Miocene (8–5 Ma). The strata suffered denudation due to the stratigraphic uplifting in the orogenic movement, resulting in the leakage of the early oil reservoir. In both categories, it suggests that the Lower Jurassic reservoirs in the Tugerming area have the favorable potential for oil and gas exploration. The understanding of hydrocarbon migration and accumulation in the Lower Jurassic reservoirs in the Kuqa Depression of Tarim Basin can contribute to the knowledge of the potential to form large oil and gas reservoirs Tugerming Area, and reservoirs of basins with a similar tectonic settings, such as the Jungar Basin.

Structural Deformation of the Northern Monoclinic Belt in the Kuqa Depression and Implications for the Cenozoic Uplift History of the South Tianshan Mountains

Structural Deformation of the Northern Monoclinic Belt in the Kuqa Depression and Implications for the Cenozoic Uplift History of the South Tianshan Mountains

Effect of the internal plastic deformation of salt structures on the lithologic succession of evaporites: A case study on the Palaeogene Kumugeliemuqun formation, Kelasu Thrust Belt, Kuqa depression, Tarim Basin

For a normal saline lake sequence, as long as the depositional setting is the same, the sediments thickness and saline lake sequence are comparable across an area. However, in the Palaeogene Kumugeliemuqun Formation, in wells from similar depositional settings and the same member, the saline lake succession varies greatly. Member 1 of the Kumugeliemuqun Formation, depending on the combination of halite, gypsum, and dolomite (limestone), is divided into four types of saline lake successions: type A, type B, type C, and type D. In the same depositional setting, the saline lake succession and sediment thickness among adjacent areas differ. In member 2 of the Kumugeliemuqun Formation, depending on the association of mudstone and halite, ten different saline lake successions were identified as sequences 1 to 10. Even within the same depositional setting, the saline lake succession and sediment thickness can differ. To explain this phenomenon, we present evidence that includes the sediment thickness, a single cycle of saline lake succession, and an ancient landform, and a salt structure to analyze the role of tectonic deformation in members 1 and 2 of the Kumugeliemuqun Formation. Moreover, waveform indication inversion was used to describe tectonic deformation patterns. The results reveal that saline succession types C and D were the result of tectonic deformation in member 1, while saline lake succession sequence types A and B were not affected by tectonic deformation in member 1. Additionally, the ten diverse saline lake succession sequences in member 2 are all the result of intense tectonic deformation. The inversion results reveal that the inclined thrust, recumbent, and sheath folding are the principal deformation styles in member 2, while flow and hook folds are the main internal deformation styles in member 1. Finally, based on these observations, we conclude that tectonic compression created the plastic flow of rock salt, which induced folding and faulting deformation. The faults produced repetition in the lithologic succession, and the folds resulted in the inversion of the lithologic succession. Therefore, due to the effects of the faults and folds, even within the same depositional setting, the lithologic succession and sediment thicknesses differ from one another. • Features of lithological successions inside salt structures are been studied. • The deformations pattern in members 1 and 2 are been described. • Effect of salt rock deformation on kinds of lithological succession is discussed. • Fold and fault in salt structures produced kinds of lithological succession.

Hydrocarbon Accumulation Process and Mechanism in the Lower Jurassic Reservoir in the Eastern Kuqa Depression, Tarim Basin, Northwest China: A Case Study of Well Tudong 2 in the Tugerming Area.

The Lower Jurassic reservoir has recently made a significant breakthrough in petroleum exploration in the Tugerming area of the eastern Kuqa depression, Tarim Basin, northwest China. Therefore, it is significantly essential to simulate the hydrocarbon charging process and analyze the accumulation mechanism in the study area. In our study, we mainly combine three geochemical techniques to identify the origin of crude oils and fluid inclusion characteristics in the target well (Tudong 2), including gas chromatography–mass spectrometry (GC–MS), comprehensive two-dimensional GC-time-of-flight MS (GC × GC–TOFMS), fluid inclusion analysis, and quantitative fluorescence technique. Combined comprehensive experiments with a set of burial history and tectonic thermal evolution history realize the reconstruction of the hydrocarbon charging process in the Yangxia formation. The results show that Jurassic coal-bearing source rocks are primary hydrocarbon sources, and there are three hydrocarbon charging events in the Lower Jurassic reservoir. First, the mature oils have expelled into the reservoir during the early-middle period (15–10 Ma) of the Miocene Kangcun Formation, forming yellow fluorescent oil inclusions and most of the quantitative grain fluorescence (QGF) indexes exceed 4. Second, numerous condensate oils have charged into the reservoir in the period of late Miocene Kangcun Formation-early Kuqa Formation (9–6 Ma), accompanied by blue-white oil inclusions and QGF on extract intensity greater than 4. Finally, vast natural gas has accumulated in the reservoir since Kuqa Formation (5–0 Ma), resulting in the adjustment of ancient reservoir and residual bitumen. Interestingly, we find that the hydrocarbon accumulation mechanism is characterized by self-generation and self-storage in the Jurassic Yangxia Formation, and the study area has prominent characteristics of late accumulation. Thus, the evidence obtained from our analysis suggests favorable geological conditions for the formation of a large oil and gas reservoir in the eastern Kuqa Depression.