Helium is an associated resource in natural gas and an important scarce strategic material. However, the research on its enrichment mechanism is relatively weak. In view of the problem of helium enrichment, geochemical method is adopted to analyze the enrichment of helium in the main helium-rich gas reservoirs in China. It is considered that the reason of the helium enrichment just in a small number of gas reservoirs is that the gas reservoir captures helium released from ancient water in old sediments. The release of helium dissolved in ancient formation water into gas reservoirs is the main mechanism of helium enrichment in helium-rich gas reservoirs. It is put forward for the first time that the formation of helium-rich gas reservoir has experienced “multi-source helium supply and main source own main helium-rich”. The helium is sourced from the radioactive decay of U and Th in hydrocarbon source rocks and reservoirs, and also from the decay of U and Th of other rocks dissolved in formation water. The main source is helium dissolved in ancient formation water, a kind of water-soluble helium which is accumulated from the decay of U and Th in old sediment. Once this kind of He-bearing water meeting the free gas or gas reservoir, because the partial pressure of helium in the water is much higher than that in the free gas or gas reservoir, according to Henry's law, the helium in the water can completely be released into the gas reservoir to form a helium-rich gas reservoir.
In order to study the geochemical characteristics, genetic types and hydrocarbon accumulation significances of coalbed methane in the Upper Permian in western Guizhou, the core testing data of 18 wells in Liupanshui, Bijie and Zunyi areas were collected and analyzed, including gas content, gas composition, stable isotope and isothermal adsorption. The results show that: the average gas content of coal is 14 m3/t and the average methane concentration of coal is 96.12%, revealing its obvious characteristics of dry gas. The δ13C1 (PDB) mainly ranges from -36‰ to -34‰, and increases with RO,max because of thermal fractionation of carbon isotope. According to the Whiticar’s discriminant chart, coalbed methane is mainly located in the thermal diffusion and migration fractionation zone. Compared with gas saturation, adsorption saturation (V/VL) can indicate coalbed methane preservation conditions and dispersion degree better, while it has a good negative correlation with δ13C1. The main mechanism is the analytical fractionation of coalbed methane carbon isotope, which can also explain synclinal-control theory of coalbed methane.
The Jiusi-Xiangbai formations of Lower Carboniferous in northwest Guizhou are important marine shale series. In order to further strengthen the basic geological survey of shale gas in Guizhou, the geological theory of shale gas with Guizhou characteristics is formed. In this paper, the exploration and development potential of shale in Jiusi-Xiangbai formations of Well Longcan 1 in Longjie Syncline of Weining is evaluated by petrology, geochemistry, reservoir physical properties and gas bearing test. The results show that: (1) The shale thickness of Xiangbai Formation is 74.76-255.6 m, the organic carbon content is medium (average，2.01%), and the thermal evolution degree is high (RO,max average，2.54% ); the microscopic components were mainly in the shell group ( average 43. 31 % ), followed by the sapropel group ( average，38.08 % ). Types of organic matter are II1 and II2. (2)The clay mineral content is relatively high (with an average mass fraction of 45.4%), followed by quartz (with an average mass fraction of 38.08%), and the brittleness index is overall high. (3)The porosity is medium ( average，4.77%), and the range of NMR permeability is large, ranging at (0.079 7-4.63)×10-6 μm2, with an average of 1.32×10-6 μm2, belonging to low permeability reservoirs; microcracks, intragranular pores, intergranular pores and organic pores are mainly developed; pore specific surface area (average 14.387 m2/g) and total pore volume ( average 0.016 76 cm3/g) are large, mainly mesoporous, average pore size is 3.79 - 8.45 nm, average 5.89 nm. (4)The gas content of the Jiusi-Xiangbai formations are moderate, up to 1.48 m3/t. It is found that TOC is the main factor affecting the gas content of mud shale. It is positively correlated with TOC and RO. In line with the conditions for industrial development, and a comprehensive comparison with the characteristics of shale reservoirs at home and abroad, it is believed that the dark shale of the Jiusi-Xiangbai formations have medium abundance of organic matter, high thermal evolution degree, high brittleness index, multiple mesoporous, and good exploration and development potential.
The discovery of Anyue giant gas field has promoted the research on in-plate fracture dynamics and se-dimentary filling process,but the current understanding of the origin and revolution of Deyang-Anyue Rift remains controversial. By interpreting large amounts of seismic data and combining latest drilling data, this paper systematically studied the origin, revolution and sedimentary filling characteristics of the rift and identified favorable exploration zones. The conclusions are as follows: Deyang-Anyue Rift was formed during Late Sinian-Early Cambrian epoch, with a differential evolution characteristic of “sedimentation in the north, erosion in the south”. The rift fractured from north to south, and platform margins were developed in the second member of Dengying Formation in Mianyang-Penglai-Dazu-Ziyang region. In the fourth member of Dengying Formation, the rift further extended south to Luzhou area. In the late depositional stage of Dengying Formation, the northern part of the rift went through sedimentation, and the southern part went through uplift and denudation, resulting in erosion of the third and fourth members of Dengying Formation in some areas. In the late depositional stage of Dengying Formation, the sedimentation volume of the northern part of Deyang-Anyue Rift was bigger than that of the southern part, and the deposition center was located in Mianyang-Chengdu region. During the late depositional stage of Maidiping Formation, sedimentation continued in the northern part and occurred in the southern part. In the depositional period of Qiongzhusi Formation, two deposition centers were formed, with Mianyang-Chengdu in the South and Yibin-Luzhou in the North. Three types of reservoirs related to platform margins were developed, including erosion type, aggradation type and retrogradation type. Combined with the thick source rocks of Maidiping-Qiongzhusi formations, two favorable exploration zones were developed in Penglai-Laoguanmiao of Jiange region and Ziyang-Weiyuan region, the exploration area of which reaches 30 000 km2.
The second member of Dengying Formation in the north slope area of central Sichuan Basin has made continuous breakthroughs in natural gas exploration in recent years. In this area, a large amount of reservoir solid bitumen was developed in the second member of Sinian Dengying Formation. Characteristics of solid bitumen are of great significance for the study of natural gas accumulation in Dengying Formation. In this paper, many solid bitumen samples of the second member of Sinian Dengying Formation were sampled from primary exploration wells. Based on a series of testing including optical microscopy, scanning electron microscopy, chromatography-mass spectrometry and laser Raman analysis, the geochemical characteristics and development mechanism of reservoir solid bitumen were studied. The results show that the solid bitumen mainly occurs in the form of dissolved pores (cave) and fractures, followed by intergranular pores. The solid bitumen morphology is characterized by point, ball, plate and vein. The average solid bitumen content of single well distributes from 2.96% to 5.13%. The solid bitumen stays in the high maturity stage, and the reflectance ratio calculated by laser Raman parameter ranges from 2.49% to 4.09%. Thermal cracking of crude oil formed the solid bitumen. In terms of biomarkers, the 21α (H)-C29 norhopane, C35 hopane and C34 hopane, and Ts/Tm of the solid bitumen of the second member of Dengying Formation are different from that of the fourth member of Dengying Formation in Gaoshiti Moxi area. It is speculated that the solid bitumen partly sourced from the Lower Cambrian Maidiping Formation and Sinian Doushantuo source rocks. Two types of solid bitumen were developed in the second member of Dengying Formation, indicating two possible stages of oil charging process. Potentially, a certain degree of thermochemical sulfate reduction (TSR) occurred.
A large-scale natural gas production base has been established in the Dengying Formation of Moxi-Gaoshiti area on the east side of Deyang-Anyue ancient rift trough in central Sichuan, which is mainly based on the platform margin zone and supplemented by the platform. The Dengying Formation in Deyang-Anyue ancient rift trough was subjected to more intense karst in the same period, and the residual hill-type reservoir of the Dengying Formation in the ancient rift trough was more developed, which was closer to the high-quality source rock of the Qiongzhusi Formation, and had the potential to form large-scale gas reservoirs. Combined with the preliminary exploration, the characteristics, formation process and accumulation conditions of residual hill-type reservoir of Dengying Formation in Deyang-Anyue ancient rift trough in central Sichuan are carefully studied. The results show that: (1) Deng 2 Member in the ancient rift trough was subjected to strong supergene dissolution and deep erosion of rivers, forming many large-scale residual hill-type reservoirs. (2) The dissolution pores, dissolution caves and fractures of the residual hill-type reservoirs of Deng 2 Member in the ancient rift trough are widely developed. The reservoir types are diverse and the reservoir thickness is thick. All kinds of reservoirs in the same residual hill-type reservoir change rapidly in vertical and horizontal directions, having large physical property differences and strong heterogeneity. (3) The distribution area of the ancient rift trough is up to 6×104 km2, the residual hill-type reservoirs of Dengying Formation is developed, which has a width of more than 40 km and a length of more than 150 km. The upper part of Dengying Formation is blocked by the source rocks of Qiongzhusi Formation and Maidiping Formation, and the lateral part of Dengying Formation is blocked by the dense layer deposited in the tight layers in the interbeach depressions. The natural gas of near high-quality source rocks is preferentially filled, and the source-reservoir-cap rock combinations are well good. The good geological conditions for the formation of multiple large residual hill-type natural gas reservoirs are in the ancient rift trough. The residual hill-type reservoirs of Deng 2 Member in the ancient rift trough are favorable for the next step of natural gas exploration.
The ability of lithologic traps to maintain long-term hydrocarbon preservation in the north slope of the central Sichuan paleo-uplift has a crucial effect on the selection of natural gas exploration targets and the scale evaluation of petroleum resources. In order to determine their capacity, the traditional relationship between the displacement pressure of mudstone surrounding rock and the residual pressure of gas reservoir was introduced into the carbonate lithologic trap of the slope area with lateral inclination angle. The results of this geological analysis, analogy, and simulation in the gas reservoir of the second member of the Dengying Formation （Z2dn2） in Well Pengtan-1 proved the preservation ability of the lithologic traps. The results show that after the formation of paleo-reservoir, the residual pressure of the reservoir gradually increased, but it was far less than the displacement pressure in the vertical and lateral surrounding rocks. Therefore, the preservation conditions were good. The inherited activities of strike-slip faults may lead to the distribution of the multi-layer paleo-oil reservoirs. During the formation of the cracked gas reservoir, though the residual pressure of the gas reservoir increased rapidly, the lateral sealing remained effective. As a result, natural gas only escaped from the upper Qiongzhusi Formation （Є1q） and unconformity interface, and most of the remaining natural gas was effectively preserved up to now. Because the lateral sealing of the Z2dn2 gas reservoir in north slope area was consistently effective, its preservation effects were similar to those in the structure-stratigraphic gas reservoir in the Gaoshiti-Moxi area. Still, compared to the reservoir preservation conditions and resource scale in the Gaoshiti-Moxi area, the Z2dn2 gas reservoir in north slope area should have better top preservation abilities and greater potential for natural gas exploration owing to the greater thickness and higher quality of the Є1q shale.
Limestone is widely developed in ultra-deep layers of petroliferous basins in China. The main mineral component of limestone is calcite. Its special crystal structure determines that it has strong plasticity and toughness in ultra-deep layers. It is not prone to fracture under small deformations. Limestone, especially marl, can also act as caprock due to its low porosity and permeability. The Yuanba gas reservoir of Sichuan Basin has a burial depth of more than 6 500 m and a large scale of gas storage. Its caprock and preservation conditions have always attracted attention. The Lower Triassic gypsum-salt rock is generally accepted as the regional caprock of the Yuanba gas reservoir, but the Feixianguan Formation limestone is still controversial as its direct caprock. Based on core observations, rock mechanical parameter testing, and geological data analysis, the integrity of Feixianguan Formation limestone as caprock is analyzed from the point of brittle-ductile property. During and after the peak gas generation period, the limestone of Feixianguan Formation has significantly improved ductile property, and its mechanical properties are in the ductile stage. It is not easy to fracture, and can maintain the integrity of the rock formation. It becomes a good caprock for dolomite reservoir of the Permian Changxing Formation. This example shows that limestone can act as a caprock in ultra-deep layers, which is of great significance for oil and gas exploration in the ultra-deep carbonate rock area.
Taking typical shale gas core wells in the Jiaoshiba area of Sichuan Basin as the research object, the application of the spontaneous development of a shale gas field desorption instrument based on the principle of drainage and gas collection, using a special desorption method to analyze the 11 organic-rich shale samples. The rock samples were desorbed, sampled and tested. The study showed that: (1) The carbon isotope fractionation effect of methane and ethane existed during the on-site desorption of shale gas. The methane fractionation amplitude was relatively large, with an average fractionation amplitude of 25.2‰, controlled by organic content. The fractionation range of ethane is relatively small, with an average fractionation range of 3.84‰. (2)There are two stages in the carbon isotope fractionation of methane and ethane in the desorption process. The methane carbon isotope fractionation process is a slow fractionation stage and a fast fractionation stage. At the end of the desorption process, there is a rapid rise of some methane carbon isotope. The ethane carbon isotope fractionation process is divided into the wave fractionation stage and the slow fractionation stage. (3)During the on-site desorption process, the methane isotope value regularly becomes heavier as the on-site desorption rate increases. Based on this phenomenon, a mathematical model of methane carbon isotope and desorption rate is established, that is, the desorption rate is the methane carbon isotope value after Exponential function with natural constant (e) as the base. The above research may be part of the understanding of the third stage of the four stage change (stable-lighter-gradually heavier-lighter) in the whole process of shale gas desorption/production, in order to provide reference for the research of the whole process of shale gas desorption/production and provide scientific basis for shale gas exploration and development.
The occurrence state and organic geochemical characteristics of shale oil are of great significance to the evaluation of sweet spot and resource potential of shale oil. In order to clarify the storage location, oil content, group component and saturated hydrocarbon distribution characteristics of shale oil from Chang 73 sub-member of the Yanchang Group in the Ordos Basin, the shale core samples of the Chang 73 sub-member were analyzed by multi-solvent continuous fractional extraction, low-temperature nitrogen adsorption, fluorescent thin-section petrological observation, field emission scanning electron microscopy and saturated hydrocarbon gas chromatography - mass spectrometry. The results show that shale oil mainly occurs in shale fractures and organic pores in Chang 73 sub-member. The total oil content of shale oil is more than 10 mg/g, of which free oil accounts for 50% and adsorbed oil accounts for 20%.The content of free oil and adsorbed oil is positively correlated with the abundance of organic matter, which indicates that the abundance of organic matter is the main factor controlling the distribution of shale oil. Free oil contains more saturated hydrocarbons and light components, while adsorbed oil contains more heavy components such as non-hydrocarbon and asphaltene. In addition, compared with dark mudstone, black shale has widely developed cleavage fractures and organic pores, and has higher free oil content, which may be a more favorable lithofacies for shale oil exploration and development.
In recent years, breakthroughs have been made in natural gas exploration around Shawan Sag, Junggar Basin, but the geochemical characteristics and distribution of source rocks in the center of the sag are still lack of systematic and comprehensive research, and the hydrocarbon generation evolution history and product characteristics of each set of source rocks are unclear, which restricts the next exploration and development of the block. Taking the source rock samples in the uplift zone as the research object, combined with seismic and hydrocarbon generation thermal simulation experiments, comprehensive evaluation of source rocks is carried out, the product characteristics of source rocks in different strata are clarified, and then the next natural gas exploration direction is pointed out. The results show that four sets of source rocks are developed in Shawan Sag, with large thickness, wide distribution area and deep burial, which lays a material foundation for oil and gas accumulation in peripheral structures. The Carboniferous and Jiamuhe Formation source rocks have high organic matter abundance, but poor type and low hydrocarbon generation potential, which are over-mature and mainly dry gas generation. The Fengcheng Formation and Lower Wuerhe Formation source rocks have high organic matter abundance and good type, which are highly mature and have great hydrocarbon generation potential. The δ13C1-RO regression equation of natural gas in Shawan Sag was established, and the carbon isotope distribution characteristics of ethane generated from source rocks in different layers were defined, which laid a foundation for the calculation of natural gas maturity and the gas source correlation in the surrounding structures. The west slope of Shawan Sag has good preservation conditions, and is located on the hydrocarbon migration path, similar to the slope of Mahu Sag, and has the geological conditions for forming large lithologic reservoirs. Therefore, it is the key field of gas exploration in the study area in the next step.
An in-depth analysis of carbon isotopic reversal mechanism of Ordovician crude oil and group composition in Tahe Oilfield, Tarim Basin is of great significance for understanding accumulation evolution and oil and gas exploration. The variation characteristics of carbon isotopes in plane and depth of 93 crude oils and group components are analyzed. δ13C asphaltene - non-hydrocarbon values in Aiding area, Tahe main area and Toputai area are -0.73‰,-0.63‰ and -0.58‰, respectively. The values are positive in area 9 and its surrounding areas as well as in southern pre-salt area. The inversion of δ13C saturated hydrocarbon and δ13C total oil occurs in some wells in Aiding area and Tahe main area. Carbon isotopes of asphaltene and other components and total oil are reversed with different degrees in different areas of Tahe Oilfield. However, the inversion distribution in depth is not correlated with the burial depth of crude oil, and the thermal effect caused by burial depth is not the main reason for the inversion of asphaltene carbon isotopes and other components in the Ordovician crude oil group in Tahe Oilfield. Combined with the contents of crude oil group components and total ion diagram of saturated hydrocarbon chromatography, it is concluded that the inversion of carbon isotope of crude oil and group components is related to biodegradation caused by formation uplift after early accumulation and multi-stage oil and gas charging. The hydrocarbon components in the early charged crude oil are mostly degraded by microorganisms, while the asphaltene is not easily degraded and retained, due to low maturity and light carbon isotopes. However, the asphaltene content in the late charged oil with high to over maturity is very low, and other components, especially saturated hydrocarbons, are the main components. Due to the high maturity, the carbon isotope of asphaltene is heavier, even heavier than that of the asphaltene carbon isotope in the early charged oil, the phenomenon of inversion of the asphaltene carbon isotope with other components occurs in the mixed oil. Therefore, the accumulation process and secondary changes of Ordovician crude oil in Tahe oilfield are the main causes of carbon isotope inversion.
The second section of Sinian Dengying Formation in Anyue Gas Field has great potential to develop, which is an important producing area of Anyue Gas Field. This reservoir has low permeability and partly developed high-porosity-permeability section. The reservoir space mainly includes karst caves, dissolution pores and fractures. The bottom water is developed in the lower part of the reservoir and the gas-water interface is unified at -5 150 m. The deep acid-fracturing technique can increase well production for such carbonate gas reservoir with low-porosity-permeability. However, there are some difficulties in acidizing fracture controlling because of natural high-angle fractures, small stress difference between sections, and the short distance between the stimulation section and the gas-water interface. It is easy to connect with the lower water layer, causing water production after stimulation. In order to explore the controlling method of acidizing fracture height, the geological and engineering influencing factors of acidizing fracture height were simulated, and a pseudo-three-dimensional extension model of acidizing fracture height was established, which considered the influence of longitudinal pressure drop on fracture height propagation in the process of fracture height propagation. The results show that the interstage stress difference and displacement are the main controlling factors of fracture height extension, and the stress difference has the greatest influence on fracture height, followed by the thickness of reservoir and interlayer and the viscosity of working fluid. The simulation results of mathematical model revealed the controlling factors and model for acid-fracturing fracture height in different reservoir characteristics. In this paper, the design parameters of acidizing controlled fracture height are optimized. Under the premise of effectively controlling the height of acid fracturing fracture, the production of single well can be maximized and water can be avoided after stimulation, which provides theoretical guidance for deep acid fracturing technology of gas reservoir with bottom water.
In Demonstration Zone, the major target horizon of shale gas development is the five meters thick Lower Silurian Longmaxi Formation marine shale. It is characterized by small target window, big structural fluctuation and small fault development, so it is possible for the actual drilling trajectory to miss the targets and run out of the target layers. By analyzing the technical difficulties during the geosteering of horizontal wells, the solutions were worked out starting from the key points of target orientation and horizontal section geosteering. (1)The optimized model eliminates the four shortcomings of the traditional modeling theory, improves the accuracy of the model to predict the landing point, ensures that the well path smoothly enters the target, while avoiding entering the target too early or late, resulting in the regularity of the well path, which is “V-shaped” or “ladder shaped”. (2)It solves three major problems in the horizontal section geosteering, such as multiple solutions, encountering fault and fold by integrating techniques including element mud logging + gamma ray control while drilling, macroscopic seismic prediction, ant-tracking attributes, and the idea of “emphasizing serious cases and ignoring minor ones” to adjust the well path. It can ensure the precision in landing and tracking horizontal section, drill-in rate and smooth well path.
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