^(68)Ga-PSMA-11 PET/CT前列腺癌假阳性病灶的病理学特点

目的基于前列腺癌根治术后标本病理大切片探究^(68)Ga-前列腺特异性膜抗原(PSMA)-11配体正电子发射/计算机断层扫描(PET/CT)前列腺癌假阳性病灶的病理特点,以期更准确地评估前列腺组织的恶性程度,避免过度诊断和不必要的治疗。方法回顾性分析2018年1月—2022年12月于南京大学医学院附属鼓楼医院行前列腺癌根治术并且术后标本制作病理大切片的77例患者的临床资料,患者术前均进行^(68)Ga-PSMA-11 PET/CT检查。2名核医学科医生盲于病理大切片对^(68)Ga-PSMA-11 PET/CT影像进行诊断,2名病理科医生盲于影像结果对病理大切片进行诊断。通过匹配影像和病理大切片来明确^(68)Ga-PSMA-11 PET/CT上前列腺内假阳性病灶,并与相应的真阴性病灶对比以明确其病理特点。采用Fisher精确检验对假阳性病灶和真阴性病灶的病理类型进行比较。结果经影像和病理大切片相互匹配后,确诊出21处(16.3%)假阳性病灶,其病理类型分别为:16处(76.2%)单纯性萎缩伴囊肿形成、3处(14.3%)前列腺增生、2处(9.5%)前列腺炎症。相应圈选的21处真阴性病灶的病理类型分别为:13处(61.9%)正常腺体结构、5处(23.8%)前列腺增生、3处(14.3%)单纯性萎缩伴囊肿形成。经Fisher精确检验发现,单纯性萎缩伴囊肿形成在假阳性病灶与其在真阴性病灶病理类型中占比的差异有统计学意义(76.2%vs.14.3%,P<0.001)。结论单纯性萎缩伴囊肿形成可能是^(68)Ga-PSMA-11 PET/CT在前列腺癌假阳性病灶中的一个特征性病理类型。

Geological Features and Reservoiring Mode of Shale Gas Reservoirs in Longmaxi Formation of the Jiaoshiba Area

This study is based on the sedimentation conditions, organic geochemistry, storage spaces, physical properties, lithology and gas content of the shale gas reservoirs in Longmaxi Formation of the Jiaoshiba area and the gas accumulation mode is summarized and then compared with that in northern America. The shale gas reservoirs in the Longmaxi Formation in Jiaoshiba have good geological conditions, great thickness of quality shales, high organic content, high gas content, good physical properties, suitable depth, good preservation conditions and good reservoir types. The quality shales at the bottom of the deep shelf are the main target interval for shale gas exploration and development. Shale gas in the Longmaxi Formation has undergone three main reservoiring stages：the early stage of hydrocarbon generation and compaction when shale gas reservoirs were first formed; the middle stage of deep burial and large-scale hydrocarbon generation, which caused the enrichment of reservoirs with shale gas; the late stage of uplift, erosion and fracture development when shale gas reservoirs were finally formed.

Formation Mechanism of the Changxing Formation Gas Reservoir in the Yuanba Gas Field,Sichuan Basin,China

In a very gentle platform-margin paleogeographic environment, platform-margin reef flat facies carbonate reservoir rocks were developed in the Changxing Formation of Yuanba field. Later weak structural evolution and diagenetic evolution caused the Changxing Formation to form lithologic traps, with good reservoirs such as dissolved bioclastic dolostone and dissolved pore dolostone. The Changxing Formation gas reservoir is a pseudo-layered porous lithologic gas reservoir under pressure depletion drive, with high H2S and moderate CO2 contents. This paper predictes that the conducting system for the Changxing Formation gas reservoir is possibly composed of the pores and microfractures in the Changxing Formation reservoir, the top erosional surface of the Changxing Formation, as well as the micropores and microfractures in the underlying formations. The Changxing Formation reservoir has experienced 3 hydrocarbon charging stages. This paper suggests that diffusion is the major formation mechanism for this gas reservoir. In the Middle and Late Yanshanian, the Yuanba area entered the major gas charging stage. The gas migrated mainly through diffusion and with the assistance of seepage flow in small faults and microfractures from the source rocks and the other oil-bearing strata to the Changxing Formation carbonate reservoir rocks, forming lithologic gas pools. In the Himalayan Epoch, the lithologic traps were uplifted as a whole without strong modification or overlapping, and were favorable for gas preservation.

Formation Mechanism and Controlling Factors of Natural Gas Reservoirs of the Jialingjiang Formation in the East Sichuan Basin

The Lower Triassic Jialingjiang Formation reservoirs are distributed widely in the East Sichuan Basin, which are composed mainly of fractured reservoirs. However, natural gas with high concentration of H2S, ranging from 4% to 7%, was discovered in the Wolonghe Gas pool consisting primarily of porous reservoirs, while the other over 20 fractured gas reservoirs have comparatively low, tiny and even no H2S within natural gases. Researches have proved the H2S of the above reservoirs are all from the TSR origin. Most of the Jialingjiang Formation natural gases are mainly generated from Lower Permian carbonate rocks, the Wolonghe gas pool＇s natural gases are from the Upper Permian Longtan Formation, and the natural gases of the Huangcaoxia and Fuchengzhai gas pools are all from Lower Silurian mudstone. The formation of H2S is controlled by the characteristics and temperature of reservoirs, and is not necessarily related with gas sources. The Jialingjiang Formation in East Sichuan is buried deeply and its reservoir temperature has ever attained the condition of the TSR reaction. Due to poor reservoir potential, most of the gas pools do not have enough room for hydrocarbon reaction except for the Wolonghe gas pool, and thus natural gases with high H2S concentration are difficult to be generated abundantly. The south part of East Sichuan did not generate natural gases with high H2S concentration because the reservoir was buried relatively shallow, and did not suffer high temperature. Hence, while predicting the distribution of H2S, the characteristics and temperature of reservoirs are the necessary factors to be considerd besides the existence of anhydrite.

Initial estimation of hydrate formation temperature of sweet natural gases based on new empirical correlation

Production,processing and transportation of natural gases can be significantly affected by clathrate hydrates.Knowing the gas analysis is crucial to predict the right conditions for hydrate formation.Nevertheless,Katz gas gravity method can be used for initial estimation of hydrate formation temperature （HFT） under the circumstances of indeterminate gas composition.So far several correlations have been proposed for gas gravity method,in which the most accurate and reliable one has belonged to Bahadori and Vuthaluru.The main objective of this study is to present a simple and yet accurate correlation for fast prediction of sweet natural gases HFT based on the fit to Katz gravity chart.By reviewing the error analysis results,one can discover that the new proposed correlation has the best estimation capability among the widely accepted existing correlations within the investigated range.

Formation of Natural Bitumen and its Implication for Oil/gas Prospect in Dabashan Foreland

Natural bitumen is the evolutionary residue of hydrocarbon of sedimentary organic matter. Several kinds of bitumen with different occurrences, including bitumen in source rock, migration bitumen filled in fault, oil-bed bitumen and paleo-reservoir bitumen, are distributed widely in the Dabashan foreland. These kinds of bitumen represent the process of oil/gas formation, migration and accumulation in the region. Bitumen in source rock fiUed in fractures and stylolite and experienced deformation simultaneously together with source rock themselves. It indicated that oil/gas generation and expelling from source rock occurred under normal buried thermal conditions during prototype basin evolution stages prior to orogeny. Occurrences of bitumen in source rock indicated that paleo- reservoir formation conditions existed in the Dabashan foreland. Migration bitumen being widespread in the fault revealed that the fault was the main channel for oil/gas migration, which occurred synchronously with Jurassic foreland deformation. Oil-bed bitumen was the kind of pyrolysis bitumen that distributed in solution pores of reservoir rock in the Dabashan foreland depression, the northeastern Sichuan Basin. Geochemistry of oil-bed bitumen indicated that natural gas that accumulated in the Dabashan foreland depression formed from liquid hydrocarbon by pyrolysis process. However, paleo-reservior bitumen in the Dabashan forleland was the kind of degradation bitumen that formed from liquid hydrocarbon within the paleo-reservior by oxidation, alteration and other secondary changes due to paleo-reservior damage during tectonics in the Dabashan foreland. In combination with the tectonic evolution of the Dabashan foreland, it is proposed that the oil/gas generated, migrated and accumulated to form the paleo-reservoir during the Triassic Indosinian tectonic movement. Jurassic collision orogeny, the Yanshan tectonic movement, led to intracontinental orogeny of the Dabashan area accompanied by geofluid expelling and paleo-reservoir damage in the Dabashan foreland. The present work proposed that there is liquid hydrocarbon exploration potential in the Dabashan foreland, while there are prospects for the existence of natural gas in the Dabashan foreland depression.

Features of Sandy Debris Flows of the Yanchang Formation in the Ordos Basin and Its Oil and Gas Exploration Significance

Sandy debris flow is a new genetic type of sand bodies,which has gained much attention in recent years and its corresponding theory is proved to be a significant improvement and even partial denial to the 'Bouma Sequence' and 'turbidite fan' deep-water sedimentary theories to some point. Oil exploration researchers are highly concerned with sandy debris flows for its key role in controlling oil and gas accumulation processes.In this article,by applying sandy debris flows theory and combining a lot work of core,outcrop observation and analysis plus seismic profile interpretation,we recognized three types of sedimentary gravity flows that are sandy debris flows,classic turbidites and slumping rocks in chang-6 member of Yanchang Formation in the deep-water area of central Ordos Basin.Among the three types,the sandy debris flows are the most prominent and possesses the best oil bearing conditions.On the contrary,the classic turbidites formed by turbidity currents are limited in distribution;therefore,previous Yanchang Formation deep-water sedimentary studies have exaggerated the importance of turbidite currents deposition.Further study showed that the area distribution of deep water gravity flow sand bodies in Yanchang Formation were controlled by the slope of the deep-water deposits and the flows had vast distribution,huge depth and prevalent advantages for oil forming,which make it one of the most favorable new areas for Ordos Basin prospecting.

Gas-hydrate formation,agglomeration and inhibition in oil-based drilling fluids for deep-water drilling

One of the main challenges in deep-water drilling is gas-hydrate plugs,which make the drilling unsafe.Some oil-based drilling fluids（OBDF） that would be used for deep-water drilling in the South China Sea were tested to investigate the characteristics of gas-hydrate formation,agglomeration and inhibition by an experimental system under the temperature of 4 ？C and pressure of 20 MPa,which would be similar to the case of 2000 m water depth.The results validate the hydrate shell formation model and show that the water cut can greatly influence hydrate formation and agglomeration behaviors in the OBDF.The oleophobic effect enhanced by hydrate shell formation which weakens or destroys the interfacial films effect and the hydrophilic effect are the dominant agglomeration mechanism of hydrate particles.The formation of gas hydrates in OBDF is easier and quicker than in water-based drilling fluids in deep-water conditions of low temperature and high pressure because the former is a W/O dispersive emulsion which means much more gas-water interfaces and nucleation sites than the later.Higher ethylene glycol concentrations can inhibit the formation of gas hydrates and to some extent also act as an anti-agglomerant to inhibit hydrates agglomeration in the OBDF.

Investigation of the hydrate formation process in fine sediments by a binary CO2/N2 gas mixture

To obtain the fundamental data of CO2/N2 gas mixture hydrate formation kinetics and CO2 separation and sequestration mechanisms,the gas hydrate formation process by a binary CO2/N2 gas mixture(50:50)in fine sediments(150–250μm)was investigated in a semibatch vessel at variable temperatures(273,275,and 277 K)and pressures(5.8–7.8 MPa).During the gas hydrate reaction process,the changes in the gaseous phase composition were determined by gas chromatography.The results indicate that the gas hydrate formation process of the binary CO2/N2 gas mixture in fine sediments can be reduced to two stages.Firstly,the dissolved gas containing a large amount of CO2 formed gas hydrates,and then gaseous N2 participated in the gas hydrate formation.In the second stage,all the dissolved gas was consumed.Thus,both gaseous CO2 and N2 diffused into sediment.The first stage in different experiments lasted for 5–15 h,and>60%of the gas was consumed in this period.The gas consumption rate was greater in the first stage than in the second stage.After the completion of gas hydrate formation,the CO2 content in the gas hydrate was more than that in the gas phase.This indicates that CO2 formed hydrate easily than N2 in the binary mixture.Higher operating pressures and lower temperatures increased the gas consumption rate of the binary gas mixture in gas hydrate formation.

Molecular Geochemical Evidence for the Origin of Natural Gas from Dissolved Hydrocarbon in Ordovician Formation Waters in Central Ordos Basin

Having studied the biomarker composition and maturity of dissolved hydrocarbons from Ordovician formation waters, the authors presented molecular geochemical evidence for the controversial origin of natural gases in central Ordos Basin.The dissolved hydrocarbons in Well Shan 12 and Well Shan 78 are relatively high in abundance of tricylic terpane, pregnane series and dibenzothiophene series and low in Pr/Ph and hopane/sterane ratios, indicating the source input of marine carbonates. In contrast, the dissolved hydrocarbons in Well Shan 81 are free from tricyclic terpane and pregnane series, with trace dibenzothiophene series and high Pr/Ph and higher hopane/sterane ratios, which are the typical features of terrestrial organic matter. Furthermore, Well Shan 37 and Well Shan 34 are between the two situations, having a mixed source of marine carbonate and terrestrial organic matter. The maturity of biomarkers also supports the above suggestions. These results are consistent with the geological background and source rock distribution in this region.

Pore Structure Heterogeneity of the Xiamaling Formation Shale Gas Reservoir in the Yanshan Area of China: Evaluation of Geological Controlling Factors

Micro-heterogeneity is an integral parameter of the pore structure of shale gas reservoir and it forms an essential basis for setting and adjusting development parameters.In this study,scanning electron microscopy,high-pressure mercury intrusion and low-temperature nitrogen adsorption experiments were used to qualitatively and quantitatively characterize the pore structure of black shale from the third member of the Xiamaling Formation in the Yanshan area.The pore heterogeneity was studied using fractal theory,and the controlling factors of pore development and heterogeneity were evaluated in combination with geochemical parameters,mineral composition,and geological evolution history.The results show that the pore structure of the reservoir was intricate and complicated.Moreover,various types of micro-nano scale pores such as dissolution pores,intergranular pores,interlayer pores,and micro-cracks are well developed in member 3 of the Xiamaling Formation.The average porosity was found to be 6.30%,and the mean value of the average pore size was 4.78 nm.Micropores and transition pores provided most of the storage space.Pore development was significantly affected by the region and was mainly related to the total organic carbon content,vitrinite reflectance and mineral composition.The fractal dimension,which characterizes the heterogeneity,is 2.66 on average,indicating that the pore structure is highly heterogeneous.Fractal dimension is positively correlated with maturity and clay mineral content,while it is negatively correlated with brittle mineral content and average pore size.These results indicate that pore heterogeneity is closely related to thermal history and material composition.Combined with the geological background of this area,it was found that the pore heterogeneity was mainly controlled by the Jurassic magmatism.The more intense the magma intrusion,the stronger the pore heterogeneity.The pore structure and its heterogeneity characteristics present today are a general reflection of the superimposed geological processes of sedimentary-diagenetic-late transformation.The influence of magmatic intrusion on the reservoir is the main geological factor that should be considered for detailed evaluation of the Xiamaling Formation shale gas reservoir in the Yanshan area.

Colloidal Gas Aphrons: A Novel Approach to Preventing Formation Impairment

Colloidal gas aphrons (CGAs) were first reported by Sebba (1971) as micro bubbles (25-125 μm), composed of a gas nucleus surrounded by a thin surfactant film and created by intense stirring of a surfactant solution. Since then, these colloidal dispersions have been used for diverse applications, with a particular focus on separation processes. However, exploitation of CGAs in petroleum industry is only at the outset. CGAs were first used in west Texas in 1998, under the name Aphron drilling fluids. This kind of fluid is characterized as having a continuous phase, a high viscosity at a low shear rate and containing, as an internal phase, micro air or gas bubbles, non-coalescing and recirculating. In this paper, we illuminate the physical and chemical properties of aphron drilling fluid and its processing mechanism.

Geochemistry, Petrology and Mineralogy of Coal Measure Shales in the Middle Jurassic Yanan Formation from Northeastern Ordos Basin, China: Implications for Shale Gas Accumulation

The Jurassic Yanan Formation is one of the most important coal-producing formations and hydrocarbon source rocks in the Ordos Basin, North China. To evaluate the shale gas potential of the Yanan shale, a total of 48 samples from north Ordos Basin were sampled, and their geochemical, petrological, mineralogical and pore characteristics were investigated. It was found that the shale samples are a suite of early mature source rock. The total organic carbon(TOC) content ranges from 0.33% to 24.12% and the hydrogen index(HI) ranges from 43.31 mg/g to 330.58 mg/g. The relationship between Tmax and HI indicates the organic matter is type Ⅱ-Ⅲ. This conclusion is also supported by the organic petrological examination results, which shows that the kerogen is mainly liptinite and vitrinite. Minerals in the samples are composed mainly of quartz, clay and feldspar, and the clay minerals are composed of prevailing kaolinite, illite/smectite, chlorite and a small amount of illite. Under scanning electron microscope, OM pores in the Yanan shale are scarce except pores come from the kerogen intrinsic texture or clay aggregates within the organic particles. As the weak compaction caused by shallow burial depth, interparticle pores and intraparticle pores are common, the hydrocarbon storage capacity of the Yanan shale was improved. According to evaluation, the Yanan shale is considered as a good shale gas reservoir, but its hydrocarbon potential is more dependent on biogenic and coal-derived gas as the thermogenic gas is limited by the lower thermal maturity.

Geological Conditions and Prospect Forecast of Shale Gas Formation in Qiangtang Basin, Qinghai-Tibet Plateau

The presence of shale gas has been confirmed in almost every marine shale distribution area in North America.Formation conditions of shale gas in China are the most favorable for marine,organic-rich shale as well.But there has been little research focusing on shale gas in Qiangtang Basin,Qinghai-Tibet Plateau,where a lot of Mesozoic marine shale formations developed.Based on the survey results of petroleum geology and comprehensive test analysis data for Qinghai-Tibet Plateau,for the first time,this paper discusses characteristics of sedimentary development,thickness distribution,geochemistry,reservoir and burial depth of organic-rich shale,and geological conditions for shale gas formation in Qiangtang Basin.There are four sets of marine shale strata in Qiangtang Basin including Upper Triassic Xiaochaka Formation （T3x）,Middle Jurassic Buqu Formation （J2b）,Xiali Formation （J2x） and Upper Jurassic Suowa Formation （J3s）,the sedimentary types of which are mainly bathyal-basin facies,open platform-platform margin slope facies,lagoon and tidal-fiat facies,as well as delta facies.By comparing it with the indicators of gas shale in the main U.S.basins,it was found that the four marine shale formations in Qiangtang Basin constitute a multi-layer distribution of organic-rich shale,featuring a high degree of thickness and low abundance of organic matter,high thermal evolution maturity,many kinds of brittle minerals,an equivalent content of quartz and clay minerals,a high content of feldspar and low porosity,which provide basic conditions for an accumulation of shale gas resources.Xiaochaka Formation shale is widely distributed,with big thickness and the best gas generating indicators.It is the main gas source layer.Xiali Formation shale is of intermediate thickness and coverage area,with relatively good gas generating indicators and moderate gas formation potential.Buqu Formation shale and Suowa Formation shale are of relatively large thickness,and covering a small area,with poor gas generating indicators,and limited gas formation potential.The shale gas geological resources and technically recoverable resources were estimated by using geologic analogy method,and the prospective areas and potentially favorable areas for Mesozoic marine shale gas in Qiangtang Basin are forecast and analyzed.It is relatively favorable in a tectonic setting and indication of oil and gas,shale maturity,sedimentary thickness and gypsum-salt beds,and in terms of mineral association for shale gas accumulation.But the challenge lies in overcoming the harsh natural conditions which contributes to great difficulties in ground engineering and exploration,and high exploration costs.

Characteristics of Organic Components in Formation Waters and Their Relations to Natural Gas Reservoirs in Central Ordos Basin

Isotachophoresis results indicate that the total concentrations of organic acids in Ordovician formation waters range from 9.17 mg/L to 94.49 mg/L and are obviously higher than those of Permo-Carboniferous formation waters. But both of them have the same compositional characteristics, i.e., acetic acid >>formic acid >propanoic acid >butanoic acid. The total alkyl phenol contents of Ordovician formation waters range from {0.57} mg/L to {4.73} mg/L, averaging {1.77} mg/L. Among the samples for phenol detection, {47.06%} samples contain less than {1.0 mg/L}, {35.29%} samples {1.0}-{3.0} mg/L, and only {17.65%} samples more than {3.0 mg/L} alkyl phenol.The concentrations of organic acids and alkyl phenols in the Majiagou formation waters are of obviously heterogeneous distribution. There are several areas where the concentrations of organic acids and phenols are high in central Ordos Basin. These organic acid- and phenol-high areas (organic acids {>45} mg/L and phenols {>2.0 mg/L}) are consistent with natural gas reservoir enriched areas in central Ordos Basin.

Genesis of the low-permeability reservoir bed of upper Triassic Xujiahe Formation in Xinchang gas field,western Sichuan Depression

The genesis of a reservoir is a result of the combined action of deposition, diagenesis, tectonic reworking, and interaction of rock and fluid and the evolutionary environment. We discuss the genetic and evolution mechanism of a low-permeability reservoir bed of the Xujiahe Formation in the western Sichuan Depression on the basis of the study of diagenesis, diagenetic reservoir facies and the diagenetic evolution sequence. The research indicated that this reservoir bed can be divided into five types of diagenetic reservoir facies, namely strong dissolution, chlorite-lined intergranular pores, compaction and pressure solution, carbonate cementation and secondary quartz increase. There are, however, just two diagenetic reservoir facies which provide low-permeability reservoir beds, namely strong dissolution and chlorite-lined intergranular pores. We also analyzed their diagenetic evolution sequences and the origin of the low-permeability reservoir bed. Besides, it was also indicated that the composition and structure of sandstones, types of sedimentary microfacies, diagenesis history as well as the tectonic reworking in later periods are the main factors controlling the formation of the low-permeability reservoir bed. The above- mentioned factors establish the foundation for the forecasting the distribution of high quality reservoir beds.

Thermochemical Sulfate Reduction in the Tazhong District,Tarim Basin,Northeast China:Evidence from Formation Water and Natural Gas Geochemistry

Systematic analyses of the formation water and natural gas geochemistry in the Central Uplift of the Tarim Basin （CUTB） show that gas invasion at the late stage is accompanied by an increase of the contents of HeS and CO2 in natural gas, by the forming of the high total dissolved solids formation water, by an increase of the content of HCO3^-, relative to Cl^-, by an increase of the 2nd family ions （Ca^2＋, Mg^2＋, Sr^2＋ and Ba^2＋） and by a decrease of the content of SO4^2-, relative to Cl^-. The above phenomena can be explained only by way of thermochemicai sulfate reduction （TSR）. TSR often occurs in the transition zone of oil and water and is often described in the following reaction formula： ∑CH＋CaSO4＋H-2O→H2S＋CO2＋CaCO3. （1） Dissolved SO4^2- in the formation water is consumed in the above reaction, when HeS and CO2 are generated, resulting in a decrease of SO4^2- in the formation water and an increase of both HeS and CO2 in the natural gas. If formation water exists, the generated CO2 will go on reacting with the carbonate to form bicarbonate, which can be dissolved in the formation water, thus resulting in the enrichment of Ca^2＋ and HCO3^-. The above reaction can be described by the following equation： CO2＋HeO＋CaCO3→Ca^2＋＋2HCO3^-. The stratigraphic temperatures of the Cambrian and lower Ordovician in CUTB exceeded 120℃, which is the minimum for TSR to occur. At the same time, dolomitization, which might be a direct result of TSR, has been found in both the Cambrian and the lower Ordovician. The above evidence indicates that TSR is in an active reaction, providing a novel way to reevaluate the exploration potentials of natural gas in this district.

Chemical kinetics evaluation and its application of natural gas generation derived from the Yacheng Formation in the deep-water area of the Qiongdongnan Basin,China

The natural gas generation process is simulated by heating source rocks of the Yacheng Formation, including the onshore-offshore mudstone and coal with kerogens of Type II2-III in the Qiongdongnan Basin. The aim is to quantify the natural gas generation from the Yacheng Formation and to evaluate the geological prediction and kinetic parameters using an optimization procedure based on the basin modeling of the shallow-water area. For this, the hydrocarbons produced have been grouped into four classes（C1, C2, C3 and C4-6）. The results show that the onset temperature of methane generation is predicted to occur at 110℃ during the thermal history of sediments since 5.3 Ma by using data extrapolation. The hydrocarbon potential for ethane, propane and heavy gaseous hydrocarbons（C4-6） is found to be almost exhausted at geological temperature of 200℃ when the transformation ratio（TR） is over 0.8, but for which methane is determined to be about 0.5 in the shallow-water area. In contrast, the end temperature of the methane generation in the deep-water area was over 300℃ with a TR over 0.8. It plays an important role in the natural gas exploration of the deep-water basin and other basins in the broad ocean areas of China. Therefore, the natural gas exploration for the deep-water area in the Qiongdongnan Basin shall first aim at the structural traps in the Ledong, Lingshui and Beijiao sags, and in the forward direction of the structure around the sags, and then gradually develop toward the non-structural trap in the deep-water area basin of the broad ocean areas of China.

Development of a least squares support vector machine model for prediction of natural gas hydrate formation temperature

Hydrates always are considered as a threat to petroleum industry due to the operational problems it can cause.These problems could result in reducing production performance or even production stoppage for a long time.In this paper, we were intended to develop a LSSVM algorithm for prognosticating hydrate formation temperature(HFT) in a wide range of natural gas mixtures. A total number of 279 experimental data points were extracted from open literature to develop the LSSVM. The input parameters were chosen based on the hydrate structure that each gas species form. The modeling resulted in a robust algorithm with the squared correlation coefficients(R^2) of 0.9918. Aside from the excellent statistical parameters of the model, comparing proposed LSSVM with some of conventional correlations showed its supremacy, particularly in the case of sour gases with high H_2S concentrations, where the model surpasses all correlations and existing thermodynamic models. For detection of the probable doubtful experimental data, and applicability of the model, the Leverage statistical approach was performed on the data sets. This algorithm showed that the proposed LSSVM model is statistically valid for HFT prediction and almost all the data points are in the applicability domain of the model.

Diagenesis and Restructuring Mechanism of Oil and Gas Reservoir in the Marine Carbonate Formation,Northeastern Sichuan:A Case Study of the Puguang Gas Reservoir

Based on the technology of balanced cross-section and physical simulation experiments associated with natural gas geochemical characteristic analyses, core and thin section observations, it has been proven that the Puguang gas reservoir has experienced two periods of diagenesis and restructuring since the Late Indo-Chinese epoch. One is the fluid transfer controlled by the tectonic movement and the other is geochemical reconstruction controlled by thermochemical sulfate reduction （TSR）. The middle Yanshan epoch was the main period that the Puguang gas reservoir experienced the geochemical reaction of TSR. TSR can recreate the fluid in the gas reservoir, which makes the gas drying index higher and carbon isotope heavier because C2＋ （ethane and heavy hydrocarbon） and 12C （carbon 12 isotope） is first consumed relative to CH4 and 13C （carbon 13 isotope）. However, the reciprocity between fluid regarding TSR （hydrocarbon, sulfureted hydrogen （H2S）, and water） and reservoir rock results in reservoir rock erosion and anhydrite alteration, which increases porosity in reservoir, thereby improving the petrophysical properties. Superimposed by later tectonic movement, the fluid in Puguang reservoir has twice experienced adjustment, one in the late Yanshan epoch to the early Himalayan epoch and the other time in late Himalayan epoch, after which Puguang gas reservoir is finally developed.