Mahu depression is the most hydrocarbon abundant depression in Junggar Basin. The slope zone of the depression is located in the advantageous oil and gas migration area with development of large-scale Triassic paleo-anticline and nose structure. It has the favorable structural conditions for hydrocarbon accumulations on a large scale. Hydrocarbon migrates along the unconformity surface between Triassic and Permian and accumulated in the nose uplift zone. The Triassic Baikouquan Formation is shallowly buried, where the fan delta frontal favorable facies zone developed. The slope zone has the geological conditions of reservoir, sealing, and conducting for large-scale hydrocarbon accumulations. Guided by the pattern of fan-controlled large-area accumulation and based on the study of the main factors controlling accumulations, it is found that the fan delta frontal facies zone controlled the physical properties and oil bearing properties of reservoirs while the facies zone and material source controlled oil and gas abundance and high yield. A number of blocks with effective and quality reserves were found on the basis of re-identifi cation of the neighboring fan bodies. Exploration practice indicates that the Triassic Baikouquan Formation in the slope zone of Mahu depression is characterized as fan-controlled large-area accumulation and becomes a new base to increase oil and gas reserves and production for PetroChina^’s Xinjiang oilfi eld.

Based on comprehensive analysis of geological, seismic, logging and testing data and focusing on three areas of sedimentation, diagenesis and breaking effect, this paper elaborates three main controlling factors of lower lithologic reservoirs of lower Ganchaigou Formation (E₃¹) below Hongliuquan Structure of Qaidam Basin – sedimentary microfacies, cementation and micro faults. The study indicates that the lithologic reservoirs of the E₃¹ in Hongliuquan Structure is not facies controlled and the sedimentary microfacies only controls distribution of sand bodies. Compactness makes the reservoir compact but exerts little impact on horizontal changes in physical properties and oil bearing properties of the reservoirs. Cementation results in sealing in the updip direction of Hongliuquan Structure, leading to a sealing zone along Hong 113 Well, Hong 22 Well and Hong 15 Well. Therefore, oil and gas are accumulated mainly in the middle position of the slope zone. Cementation minerals are mainly anhydrite, gypsum and calcite. Micro fault development zone is the main oil and gas bearing zone in Hongliuquan Structure. The differences in sealing conditions of different micro faults are the important controlling factors for lithologic reservoirs, causing the apparent difference in the oil bearing properties of neighboring wells.

Based on drilling of Carboniferous-Lower Permian and comparison of the organic geochemical characteristics of outcrop limestone and mudstone in Turpan-Hami Basin, this paper elaborates the influence of weathering effects on organic characteristics of source rock. The analysis indicates that organic abundance of mudstone is generally higher than that of limestone. So far as hydrocarbon source rock is concerned, mudstone is better than limestone thanks to the different sedimentary environment and material sources. The conserving conditions for samples of fi eld outcrops are apparently poorer than those samples of source rock in the deep layers of the basin. If the samples from the same strata and the same lithology become different, at the drilling and outcropping, this phenomenon is related to weathering effects. Weathering effects can exert infl uence on total components of dissoluble organic matters and hydrocarbon content of middle and lower molecules, causing more serious damage on dissoluble organic matters than solid dissoluble organic matters. As compared to limestone, mudstone can more strongly resist weathering effects.

The tight oil reservoir in the northern part of Songliao Basin is the sedimentation of semi-deep to deep lacustrine facies mingled with delta frontal subfaices and fluvial facies. It is characterized as decentralized longitudinally, instable horizontally, small in sweet-point scale, poor fl at connectivity, changeable in physical properties, and different in oil bear properties. The mechanical difference, caused by strong heterogeneity, makes fractures extend non-uniformly and leads to more fracturing sections and a larger fracturing scale so that high requirements are set on the proppant, raw materials and operational facilities. Equal fractural spacing fracturing design is not suitable in this region. To solve this problem, the techniques for stimulation design have been developed for optimization of fractural spacing, division of fracturing sections, optimization of perforation, optimization of fractural length and height and optimization of fractural conductivity so that optimization of fractural system can be achieved in volumetric fracturing of heterogeneous reservoirs. Meanwhile, optimization arrangement of fracturing fl uid, proppant and surface facilities met the requirements for a large-scale volumetric renovation of tight oil reservoir in northern part of Songliao Basin. A total of 10 wells with 97 sections were tested on the fi eld. The single-well production reached 40 ^m3/don average, 17 times as high as that from the neighboring straight wells with the same conditions of physical properties. Continental heterogeneous tight oil reservoirs were brought under effective renovation. The techniques are of a great signifi cance to Daqing to increase tight oil reserves and production.

Wave field separation is to decompose hybrid wave field into pure compress wave and pure shear wave so that the propagation law of compress wave and shear wave in the medium can be studied more accurately. Operator separation is adopted to construct the first-order hyperbolic type elastic wave equation to achieve elastic wave field separation numerical modeling. In numerical process, equal energy source and longitudinal wave source are used as excitation source while the high-order staggered grid finite difference technique is used to simulate elastic wave equation. This method can successfully and effectively separates pure compress wave and pure shear wave from hybrid wave, with good stability and high accuracy. This study is of great signifi cance to research on elastic wave propagation, seismic data acquisition and processing, and elastic wave migration imaging.

Giant carbonate rock oil and gas fi elds are those whose reservoirs are made mainly of carbonate rock. Based on the statistical fi gures, at the end of 2012, a total of 1021 giant oil and gas fi elds were found worldwide, of which 321 ones were giant carbonate rock oil and gas fi elds. By means of statistical analysis, assessment of resources and sedimentology, this paper theoretically analyzes 226 giant carbonate rock oil and gas fi elds, focusing on their geographical locations, strata distribution, scale and buried depth of reservoirs, and types of traps. The analysis indicates that carbonate rock reservoirs are distributed mainly in the Persian Gulf Basin, the Gulf of Mexico Basin, Sirte Basin, Pre-Caspian Basin, North Slope of Alaska in the United States, Permian Basin, Sichuan Basin and Tarim Basin. Of those areas, the oil and gas resources of carbonate rock reservoirs are accumulated mainly in the Upper Paleozoic , Jurassic System, Cretaceous System, Paleogene System and Neogene System. Giant carbonate rock oil and gas fi elds can be classifi ed mainly as biological reef, grain beach, dolomite, unconformity and weathering crust. Usually they are large in scale, with a buried depth of less than 3000 meters. However, the reservoirs with a large buried depth are mostly dolomite and high-pressure limestone. Based on the research on distribution patterns and accumulations of giant carbonate rock oil and gas fi elds, it is found that the current geophysical locations and vertical distribution of giant carbonate rock oil and gas fi elds are controlled by the carbonate rock plane and distribution of strata. The palaeoclimate and palaeolatitude controlled formation of hydrocarbon source rock and development of carbonate rock. The palaeostructure and its development controlled the scale of carbonate rock reservoirs and oil and gas abundance. The sedimentary diagenesis controlled reservoir functions of giant carbonate rock oil and gas fi elds while favorable source-reservoir-cap assemblage holds the key to formation of giant carbonate rock oil and gas fi elds.

The pre-salt deepwater of South Atlantic Ocean basins have become the hot areas of oil exploration. These basins have experienced the similar tectonic and sedimentary evolution and similar petroliferous geological conditions. Major discoveries have been continually made in the basis of Brazil^’s coast in recent years, but no breakthroughs have been made in pre-salt exploration of the basins of West Africa^’s coast. This paper selects three important basins – Santos, Campos and Kwanza – to compare their pre-salt geological characteristics and analyze their basin framework, sedimentary reservoirs and source rock characteristics. According to this paper, the basin framework controls sedimentary reservoir development, thus controlling oil and gas accumulations. Brazil^’s Santos Basin and Campos Basin are in the patterns of ^“two depressions and one uplift^” and ^“two depressions and three uplifts^” respectively. The depressions are favorable hydrocarbon sourcing zones while the uplifts are favorable hydrocarbon accumulations zones, accumulated on a large scale and in concentration. West Africa^’s Kwanza Basin is nearly in the pattern of ^“three depressions and two uplifts^” ,it conjugates with Campos Basin. But the pre-salt structure is mainly composed of faulted blocks mixed with horsts and grabens at a small scale and in dispersion, distributed in a narrow-ribbon shape. All the three basins of Santos, Campos and Kwanza have abundant pre-salt lacustrine source rock, deposited under the salt lake environment and containing kerogen of Ⅰ - Ⅱ type. Drilling has confi rmed such source rock. Two sets of reservoir developed in the pre-salt formations of Brazil’s Santos and Campos basins, namely late syn-rift bioclastic limestone and sag microbialites. The recent oil and gas discoveries in West Africa^’s Kwanza basin indicate that the similar reservoirs also exist in the pres-salt formations of the basin.

Based on a comprehensive analysis of source rock distribution, reservoir characteristics, cap rock characteristics and trap types in typical hydrocarbon basins in North Africa, this paper summarizes the basic characteristics of reservoir-cap assemblages in the region. The study indicates that source rock of reservoir-cap assemblages in North Africa is fairly homogenerous, mainly the Lower Silurian and Middle-Upper Devonian “hot” shale, distributed in large areas with huge sourcing potential. All Paleozoic sandstone is reservoir in various hydrocarbon basins. It is mainly the reservoir of Ordovician System and Devonian System. However, the reservoirs in different regions have different characteristics. Triassic reservoirs are distributed in large areas in Ghadames Basin. The main cap rock is Lower Silurian and Upper Devonian shale while the secondary cap rock is Carboniferous and Lower Devonian shale and carbonate rock, with development of structural traps, stratigraphic traps and structural-stratigraphic compound traps. Different traps shaped different oil and gas reservoirs. There are three main patterns for oil and gas migration in the study zone, mainly the horizontally long-distance or short distance migration. Following analysis of the characteristics of reservoir-cap assemblages in Paleozoic hydrocarbon basins in North Africa, it is assumed that Ghadames Basin is richest in remaining oil and gas reserves and matched with desirable reservoir-cap assemblages. Thanks to a variety of traps, advantageous reservoir conditions and a low level of exploration and development, Ghadames Basin has the greatest potential for exploration in Paleozoic hydrocarbon basins in North Africa.

Chang 7 oil formation in Ordos Basin is distributed in the center of lake basin in a large area. The porosity ranges mainly from 4 percent to 12 percent while the permeability is less than 0.3mD. It is a typical tight sandstone reservoir. Determination of the lower limits of effective reservoir is one key technologies to divide the oil-bearing boundary of tight rock. Based on the geological data, such as logging interpretation, oil testing data and analysis of physical properties of reservoirs and in accordance with the statistical principles and super-low permeable oil reservoir fl uid fi ltration mechanism, fi ve methods are adopted to the lower limits of physical properties of the effective reservoirs in this block, such as experience statistical method, physical oil testing method, porosity-permeability intersection method, oil and gas displacement simulation method and minimum fl owing pore throat radius method. The lower limit of physical properties of effective reservoir in Chang 7 oil formation is determined on the basis of the research and comparison. The porosity and permeability are 5.7 percent and 0.0276mD.

Based on the seismic and core data, slices and geochemical analytic data, this paper analyzes the geological factors of lower Es₁ tight sandstone oil in Qibei Slope of Qikou depression and clarifies the exploration potential in this area. The study indicates that the stable and gentle structural background of lower Es₁ in Qibei slope, high-quality source rock in a large area, distribution of heterogenerous tight sandstone reservoir in a large area, co-existence of source and reservoir and near-distance migration and accumulations are favorable for formation of tight oil on a large scale. Lower Es₁ of Qibei slop developed muti-times offshore subaqueous fan, the middle fan subfacies and the physical properties of reservoirs in the fault development zone are relatively desirable, leading to development of conventional oil reservoirs. The outer fan subfacies with development of thin tight sandstone distributed with tight oil in a large area, shaping a series of oil reservoirs overlapped vertically and horizontally with conventional oil reservoirs and tight sandstone oil reservoirs in this area. Based on prediction of reservoir, tight oil is estimated to be distributed in a 163km². The sweet-spot zone of the turbidite sand sheet in the upper section of Ban2 thin layer is the fi rst choice for tight oil exploration.