With the aim of exploring the diagenetic characteristics, influence mechanisms, and distribution of dominant diagenetic facies in the Fengcheng Formation, at the southern margin of Mahu Sag in the Junggar Basin, this paper quantitatively characterized the reservoir transformation intensity of compaction, cementation, and dissolution on the basis of the analysis of petrological characteristics, pore types, diagenesis, and diagenetic environment evolution, and established a diagenetic facies division scheme. Based on single-well core interval evaluations, the diagenetic facies distribution was described, and the mechanisms influencing their distribution were explained. The results show that the reservoir space in the Fengcheng Formation is characterized by a dual medium of “matrix-pores dominated and micro-fractures supplemented”, with intra- and intergranular dissolved pores being predominant types in matrix pores. The Fengcheng Formation underwent an evolution through an alkaline sedimentary environment and an alkali-acid-alkaline diagenetic sequence. During the alkaline sedimentary and early alkaline diagenetic stages, significant intergranular pore loss occurred due to cementation, while volcanic material hydrolysis and plagioclase albitization facilitated the formation of solution pores. The reaming in the acidic diagenetic environment in the middle stage caused additional dissolution pore become the main reservoir space, and mitigating the densification to some extent. In the late alkaline diagenetic environment, the concentration of alkaline mineral ions increased, leading to precipitation in the remaining intergranular pores, solution pores, and other reservoir spaces, and the reservoir densification degree is further improved. In the study area, the cementation and dissolution of fan delta plain and front junction were weak, resulting in more compact phases developed, with an average porosity of about 4.9%. Moving from the inner front of the fan delta to the junction of the outer front, dissolution became more dominant than cementation, leading to development of cementation-dissolution phases, with an average porosity of about 6.6%. The dissolution phases near the central and southern faults prevailed, with an average porosity of 9%. The outer front of the fan delta is mostly associated with solution-cementation facies, resulting in an average porosity of the reservoir of about 3.1%. In general, alkaline diagenesis in the alkaline lake sedimentary setting has a dual effect on reservoir reconstruction. The cementation-dissolution and dissolution phases, under the control of acid/alkaline dissolution process, are favorable sites for tight oil accumulation in this area, and are also the key factors for the high productivity in this area.

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The intricate distribution of oil and water in tight rocks makes pinpointing oil layers challenging. While conventional identification methods offer potential solutions, their limited accuracy precludes them from being effective in their applications to unconventional reservoirs. This study employed nuclear magnetic resonance (NMR) spectrum decomposition to dissect the NMR T2 spectrum into multiple sub-spectra. Furthermore, it employed laboratory NMR experiments to ascertain the fluid properties of these sub-spectra, aiming to enhance identification accuracy. The findings indicate that fluids of distinct properties overlap in the T2 spectra, with bound water, movable water, bound oil, and movable oil appearing sequentially from the low-value zone to the high-value zone. Consequently, an oil layer classification scheme was proposed, which considers the physical properties of reservoirs, oil-bearing capacity, and the characteristics of both mobility and the oil-water two-phase flow. When applied to tight oil layer identification, the scheme's outcomes align closely with actual test results. A horizontal well, deployed based on these findings, has produced high-yield industrial oil flow, underscoring the precision and dependability of this new approach.

The tight reservoirs of the Fengcheng Formation at the southern margin of the Mahu Sag have strong heterogeneity due to the diversity in their pore types, sizes, and structures. The microscopic characteristics of tight reservoirs and the mechanisms that generate them are of significance in identifying the distribution of high-quality reservoirs and in improving the prediction accuracy of sweet spots in tight oil reservoirs. In this paper, high-pressure mercury intrusion (HPMI) and nuclear magnetic resonance (NMR) experiments were carried out on samples from the tight reservoirs in the study area. These experimental results were combined with cluster analysis, fractal theory, and microscopic observations to qualitatively and quantitatively evaluate pore types, sizes, and structures. A classification scheme was established that divides the reservoir into four types, based on the microstructure characteristics of samples, and the genetic mechanisms that aided the development of reservoir microstructure were analyzed. The results show that the lower limit for the tight reservoir in the Fengcheng Formation is Φ of 3.5% and K of 0.03 mD. The pore throat size and distribution span gradually decrease from Type I, through Type II and Type III reservoirs to non-reservoirs, and the pore type also evolves from dominantly intergranular pores to intercrystalline pores. The structural trend shows a decrease in the ball-stick pore-throat system and an increase in the branch-like pore-throat system. The dual effects of sedimentation and diagenesis shape the microscopic characteristics of pores and throats. The sorting, roundness, and particle size of the original sediments determine the original physical properties of the reservoir. The diagenetic environment of ‘two alkalinity stages and one acidity stage’ influenced the evolution of pore type and size. Although the cementation of authigenic minerals in the early alkaline environment adversely affected reservoir properties, it also alleviated the damage of the later compaction to some extent. Dissolution in the mid-term acidic environment greatly improved the physical properties of this tight reservoir, making dissolution pores an important reservoir space. The late alkaline environment occurred after large-scale oil and gas accumulation. During this period, the cementation of authigenic minerals had a limited effect on the reservoir space occupied by crude oil. It had a more significant impact on the sand bodies not filled with oil, making them function as barriers.

The grading evaluation of shales helps in understanding theshale reservoir formation and sweet-spot screening of physical properties.Reservoir formation of shale is closely related to the size, distribution, andconnectivity of shale pore-throats. Therefore, characterization andclassification of microscopic pore-throats are the basis for shale reservoirgrading. However, previous microscopic pore-throat classification schemesfor materials science are unsuitable for shales with strong heterogeneity. Inrecent years, the author's team has proposed a new classification method formicroscopic pore-throats of shale reservoirs based on the comprehensivecharacterization of numerous shales with varied maturities in different basins.Results show that the microscopic pore-throats for all shales can be dividedinto micropores, small pores, mesopores, and macropores. The component,size, and distribution of microscopic pore-throats in shales in different basinsdiffer due to the differences in mineral composition and diagenetic evolutionof shales caused by varying depositional environments and burial histories.Correspondingly, the demarcation points of different types of pore-throatsare different. After clustering statistical analysis of different types ofmicroscopic pore-throats, shales can be divided into grade I, II, III, and IV reservoirs, regarded as good, medium, poor, andnonshale reservoirs, respectively. Grading evaluation criteria for shale reservoirs were then established. Further, a new technique forevaluating the reservoirflow zone index (FZI) and dividingflow units based on logging data was constructed using the relationshipof permeability with porosity in the same hydraulicflow unit. The grading evaluation criteria can be applied to single wells,multiwells, and planes using logging data. The application in numerous shale oil and gas exploration areas in China shows that theestablished classification scheme can be applied to the grading evaluation and sweet-spot screening of shale reservoirs

Understanding fluid mobility during spontaneous imbibition (SI) and flooding is important for the enhancement of oil recovery. Many researches on SI, water flooding (WF), and N2 flooding (NF) have been published, but an indepth understanding of the oil mobility at the pore scale is still inadequate in low-permeability reservoirs. To solve this problem, SI, WF, and NF experiments were performed on the low-permeability conglomerates of the Baikouquan Formation and the Urho Formation in the Mahu Sag. Moreover, online NMR was introduced to monitor the oil volume in pores with different sizes in real-time. Considering the wettability, mineral compositions, and pore structure, we established a schematic diagram to reveal the fluid mobility mechanism. The results show that the micropores in the low-permeability conglomerates are more hydrophilic, whereas the other pores are more lipophilic. During SI, the movable oil is mainly distributed in the micropores in the form of claybound oil (CBO), which is discharged from the rock through the meso/macropores. High hydrophilicity contributes to a high imbibition rate and oil recovery from SI, while the pore structure only affects the imbibition rate. During WF, the movable oil is contributed by CBO in the micropores and free oil (FO) in the pores controlled by throats >0.3 mu m. During NF, the movable oil is mainly distributed in the pores controlled by > 0.1 mu m throats, existing as FO and part capillary-bound oil (CAO). The results demonstrate that NF is effective to enhance the oil recovery of tight reservoirs, while WF is only effective for tight reservoirs with better pore structure (high Vr > 0.3 mu m).

The Ri-Qing-Wei Basin is a newly discovered Late Mesozoic rift basin on the eastern Shandong coast in recent years. Thick, continuous deposited source rocks are found in the Lingshan Island scientific drilling project. Therefore, it is necessary to evaluate the distribution and hydrocarbon generation potential of source rocks in this area. Organic geochemical experiments were carried out on samples from the core of LK-1 and outcrops in the Lingshan Island, the Laoshan area, and the Jimo Zhougezhuang area to evaluate the maturity, abundance, and type of organic matter in source rocks. The results show that the cumulative thickness of the source rocks in the study area is more than 500 m, and the TOC content is generally greater than 1.0%. The organic matter type is good (mainly type II1 and type II2 kerogen) and the Ro value is more than 2.0. The thermal evolution degree of the organic matter is high with natural gas predominantly generated. We carried out Rock-Eval, PY-GC and gold tube experiments on low-maturity samples of Laikong 2 and established a chemical kinetic model to quantitatively evaluate the study area in combination with sedimentary burial history and thermal history data. The results show that the total resources of the five sags in the study area are about 476 billion cubic meters, and the average resource intensity is about 82.2 million cubic meters/km2. Among them, the resource intensities of the Lingshan Island Sag and Laoshan Sag are 112.6 million cubic meters/km2 and 98.8 million cubic meters/km2, respectively. Studied sites are “small and fertile” and may be used as favorable exploration prospect areas.

Based on the microscopic pore-throat characterization of typical continental tight reservoirs in China, such as sandstone of Cretaceous Qingshankou and Quantou formations in Songliao Basin, NE China sandy conglomerate of Baikouquan Formation in Mahu area and hybrid rock of Lucaogou Formation in Jimusaer sag of Junggar Basin, NE China the theoretical lower limit, oil accumulation lower limit, effective flow lower limit and the upper limit of tight oil reservoirs were defined by water film thickness method, oil bearing occurrence method, oil testing productivity method and mechanical balance method, respectively. Cluster analysis method was used to compare the differences in pore-throat structure of different tight reservoirs, determine the grading criterion of tight reservoirs, and analyze its correlation with the limit of reservoir formation. The results show that the boundary between tight reservoir and conventional reservoir corresponds to the upper limit of physical properties, the boundary of class II and class III tight reservoirs corresponds to the lower limit of effective flow, the boundary of class III and class IV tight reservoirs corresponds to the lower limit of reservoir forming, and the theoretical lower limit of tight reservoir corresponds to the boundary between tight reservoir and non-reservoir. Finally, the application results of the grading evaluation criterion show that the tight oil productivity is highly controlled by the type of tight reservoir, and class I and class II tight reservoirs are the favorable sections for high production of tight oil.

目前实施的有机质丰度评价行业标准并不适用于中-高演化阶段烃源岩.为了实现此类烃源岩品质的精细分类评价,该文基于烃源岩原始生烃潜量与残余有机碳含量以及残余生烃潜量关系,建立了不同演化阶段烃源岩有机质丰度评价标准,探讨了烃源岩岩性、干酪根类型以及热演化程度对评价指标界限划分的影响.研究表明,中-高演化阶段烃源岩丰度指标划分界限明显低于行业标准,总体上表现为随热演化程度的增加评价指标界限逐渐降低,且随着有机质类型变差、评价指标界限逐渐升高的趋势.虽然碳质泥岩有机碳含量和生烃潜量要高于泥岩,属于品质较好的气源岩,但并不一定是较好的生油岩.不同含油气盆地由于烃源岩岩性、有机质类型和热演化程度存在差异,其评价指标界限难以统一,但可借鉴该文方法分别建立,为烃源岩的精细分类评价和有利区带优选提供依据.

Pore types strongly influence fluid mobility of reservoirs. For a given porosity in different rocks, the movable fluid saturation can differ> 30%. Previous studies commonly attribute this phenomenon to the differences in throat but ignore the importance of pore types. An effective method, which integrates nuclear magnetic resonance, LAVFS-SEM and nitrogen gas adsorption experiments, was established to quantitatively investigate the abundance and size distributions of different pore types, and their control on fluid mobility in conglomerates from the Mahu Sag, China. Furthermore, the geological control of intergranular (dissolution) pores (InterG-Ds) is analyzed. The pores characterized by N(2)GA are mainly clay-related pores (CRPs), and the shape of hysteresis loop is related to the type of clay minerals. InterG-Ds are mainly distributed > 1 mu m, corresponding to the P3 and P2 in T-2 spectrum. Intragranular dissolution pores range from tens of nanometers to ten micrometers, associated with P-2 and P1. CRPs are below 900 nm and associated with P1. The content of InterG-Ds controls fluid mobility of conglomerates. 190 x 10(-4)mL/g is the lower limit of InterG-D volume, which can judge that the continuous percolation network (CPN) is composed by only InterG-Ds. 45 x 10(-4)mL/g is the upper limit of the InterG-D volume to determine that the CPN consists of only CRPs. With the decrease of InterG-D volume, both movable fluid porosity and permeability reduce. Good sorting and abundant rigid particles are prerequisites for the development of InterG-Ds. Cementation can significantly reduce InterG-Ds volume, while feldspar dissolution can increase InterG-D volume.

为了有效评价砾岩致密油藏"甜点"分布,针对砾岩致密油藏非均质性强、油水分布复杂、"甜点"识别困难等问题,对风南4井区砾岩致密样品孔隙度、含油饱和度开展地层条件下的恢复校正,并结合阿尔奇公式以及动态地层水电阻率评价模型建立相应的孔隙度与含油饱和度测井评价模型;在此基础上,通过构建含油孔隙度参数,刻画单井垂向含油非均质性从而实现砾岩致密油藏地质"甜点"测井评价.研究结果表明:相比于地表检测值,地层条件下孔隙度减少约12.5％,含油饱和度增加9.3％左右;砾岩油藏"甜点"主要分布在T1b21及T1b3段,以II类"甜点"为主,其次为I类"甜点".地质"甜点"的识别与评价可为玛湖地区砾岩致密油藏井位部署及水平井轨迹优化提供参考.

致密储层微观结构影响着原油在储层中的充注行为,制约着致密油的富集和分布规律.基于致密油充注模拟、恒速压汞、扫描电镜与核磁共振等实验,文章定量表征致密储层的原油充注行为和孔喉结构特征,剖析成岩作用、自生矿物生长形态以及孔喉结构特征对原油在致密储层中充注行为的影响.研究表明,原油充注过程可分为3个阶段:充注启始阶段、快速充注阶段和缓慢充注阶段,这是充注过程中驱替压力与毛管力的动平衡以及主要储集空间分布的结果.其中,快速充注阶段又存在两种增长模式,即持续增长模式和跳跃增长模式,这两种模式揭示了主流喉道半径分布特征的差异.通过分析发现,压实、胶结、溶蚀、自生矿物生长等成岩作用极大程度上影响着储集空间和喉道半径的尺寸和分布,决定了致密储层品质的优劣.故此,在油源充足的条件下,具备足够的驱动力和品质优良的储层,是致密油富集的关键,而开启的断层/微裂隙附近的砂体正是满足这些条件的有利区带.

The pore size distribution (PSD) and fluid mobility parameters are vital parameters for predicting rock properties and the reservoir quality classification. Because of the characteristics of strong heterogeneity, a complex pore-throat structure, and a wide PSD of glutenite, it is more difficult to acquire the full-range PSD and fluid occurrence states of glutenite. This paper investigates the full-range PSD, the distribution, and the controlling factors of the movable oil in glutenite based on various experiments. X-ray diffraction, casting thin sections, scanning electron microscopy (SEM), low-temperature nitrogen adsorption (LTNA), high-pressure mercury intrusion, and nuclear magnetic resonance (NMR)-centrifugation experiments were conducted on 18 glutenite samples from the Mahu Sag, Junggar Basin, China. A new method for characterizing the full range PSD of glutenite was proposed by integrating LTNA and NMR-centrifugation experiments, and the full-range PSD is in good agreement with the casting thin sections and SEM images. Moreover, in terms of the distribution patterns of the T-2 spectra under the n-dodecane saturation condition, the glutenite samples are divided into four categories (i.e., type-I, type-II, type-III, and type-IV). From type-I to type-IV, both the pore size and the movable oil saturation of glutenite samples show a gradually decreasing trend. In addition, the movable oil mainly occurs in the pore-throat configurations of type-A, type-B, and type-C in glutenite. The development of the different types of pore-throat configurations is controlled jointly by the sedimentary compositions and mineral compositions. For higher quartz clastic and feldspar mineral contents and lower calcite and clay mineral contents, glutenite is more developed in type-A, type-B, and type-C pore-throat configurations. The above findings will provide intellectual support for identifying high-quality glutenite reservoirs and improving the productivity of glutenite oil reservoirs.

Based on the restoration of original oil saturation and the relationship between oil-bearing porosity (product of oil saturation and porosity) and oil recovery strength of single well, the geological "sweet point" classification evaluation criteria for conglomerate tight reservoirs was established.On the basis of logging evaluation of reservoir porosity and original oil saturation, and referring to the "sweet point" classification criteria, the geological "sweet point" intervals and horizontal distribution of Baikouquan formation in Mahu depression were described.The results show that the conglomerate tight reservoirs can be divided into four types:typeⅠ "sweet point", typeⅡ "sweet point", low efficiency oil reservoir and dry layer.The "sweet point" reservoirs are mainly developed in the T1b1 and T1b2 members in Ma 18 well area, where typeⅠ "sweet point" reservoirs are mainly developed in the T1b1 member.The "sweet point" of Ma 131 well area are mainly developed in the T1b2 and T1b3 members.Among them, the development level of "sweet point" of T1b3 member is the same as that of T1b2 member in Ma 18 well area, which are mainly typeⅡ "sweet point".The T1b2 member mainly develops typeⅡ "sweet point" reservoir, low efficiency oil reservoir and dry layer.From the single well productivity, the reservoirs with the highest daily production are developed in the T1b1 member of Ma 18 well area, followed by the T1b2 member in Ma 18 well area and theT1b3 member in Ma 131 well area, and the lowest daily production is the T1b2 member in Ma 131 well area.The identification of "sweet point" in conglomerate reservoir is of great strategic significance for reducing exploration risk and realizing the scale development of tight conglomerate reservoirs.

Based on data of thin section and SEM as well as the observations of rate-controlled mercury injection,the influence of diagenesis on the micro-and nano-scale reservoir spatial evolution,as well as the occurrence and distribution of tight oil and gas were analyzed in Quantou4 member of southern Songliao Basin. The results show that the diagenetic environment experi-enced a transition from alkalinity through acidity to alkalinity. During the formation of authigenic minerals in different diagenet-ic environments,a large number of nano-scale intercrystalline pores were also formed when the minerals cemented and/or filled the micro-scale reservoir spaces. Because of the transformation of reservoir spaces from micro-scale to nano-scale, the storage capacity and percolation ability of tight sandstones are reduced,and the driving force is enhanced in the process of tight oil and gas charging,which led to the mercury saturation of throat and the breakthrough pressure increase gradually with the decrease of porosity and permeability in rate-controlled mercury injection experiments. The migration and accumulation of tight oil and gas is the result of dynamic mechanical equilibrium. Therefore,the exploration and development of tight oil and gas in areas far a-way from source rocks should be pivoted around the sandstones dominated by the micro-scale spaces,whereas the exploration of near-source tight oil and gas should be expanded to the sandstones dominated by the nano-scale spaces.

There are many hydrogen-bearing components in shale, including kerogen, free oil, adsorbed oil, free water, adsorbed water, and structural water. Measuring the content and distribution of each component is important to understand the occurrence mechanism of shale oil. The nuclear magnetic resonance (NMR) T-1-T-2 map can be used as a non-destructive technique to distinguish hydrogen-bearing components in shale. In this paper, we examine the relaxation characteristics of kerogen, shale, and clay minerals in continental shale under different oil or water conditions using high-resolution low-field NMR instruments (frequency is 21.36 MHz, and echo time is 0.07 ms). The NMR T-1-T-2 map division method was established for each hydrogen-bearing component. The relaxation characteristics of each component are as follows: (1) Kerogen has the highest T-1/T-2 ratio; oil exhibits a higher Ti/T, ratio than that of water; and the mobility of water is greater than that of oil under saturated conditions. (2) The transverse relaxation time of the free state is greater than the adsorbed state for oil and water. (3) Intergranular pores of clay-rich continental shale shrink after saturation with water and result in the main peak of the T-2 value of free water at less than 1 ms, which differs from marine shale. (4) Kerogen and structural water account for a large proportion of NMR signals in continental shale. (5) The signals of some components in T-1-T-2 maps overlap because of the resolution limitation of the NMR instrument. Organic matter abundance and oil saturation of shale, estimated by the NMR T-1-T-2 map method, were in good agreement with the pyrolysis and distillation experiments, which demonstrates the reliability of the NMR T-1-T-2 map division method for each hydrogen-bearing component in continental shale.

Tight sandstone gas reservoirs have been studied throughout the world, whereas sandy conglomerate gas reservoirs in faulted basins are seldom analyzed. For the purpose of providing guidance for reservoir prediction, characteristics and origin of high porosity in nanoporous sandy conglomerates from Shahezi formation of Xujiaweizi fault depression have been studied by exploiting technologies such as cast thin section observation, SEM, constant rate mercury penetration, NMR, etc. The results show that sandy conglomerates in Shahezi formation are so tight that the reservoir pores are nanometer grade with a main range size of 10 nm-1000 nm. High porous sandy conglomerates which produce more gas and supposed to be the sweet points were defined as reservoirs with porosity more than 5.0%. Microscopically, high porous sandy conglomerates are characterized with positively correlated porosity and permeability, high large pore proportion and good pore-throat connectivity. Genetic of high porous sandy conglomerates are closely related to sedimentation and diagenesis. Favorable mineralogical composition for their formation are the volume content of quartz more than 17.6%, mud matrix less than 14.2%, clay minerals less than 27.1% and carbonate cements less than 4.8%. Favorable sedimentary facies such as distributary channel in a fan delta or braided river delta, where sandy conglomerates are not only higher in original porosity but also less compacted and stronger dissoluted during the diagenesis process are the congenital conditions for the origin of high porous sandy conglomerates.

Cretaceous Qingshankou ([Formula: see text]) mudstone of lacustrine origin is the major source rock for conventional hydrocarbon currently being produced in the Daqing and Jilin oilfields of the Songliao Basin, which is one of the largest continental basins in the world. Therefore, elucidating the geochemical and petrological characteristics of the [Formula: see text] mudstone is important to help determine its quality as an economically viable source for shale oil production. In our study, eight dark mudstone core samples from the [Formula: see text] formation were subjected to total organic carbon (TOC), Rock-Eval pyrolysis, X-ray diffraction, scanning electron microscopy (SEM), field emission SEM (FE-SEM), and low-pressure [Formula: see text] gas adsorption (LPGA-[Formula: see text]) experiments. Geochemical and petrological analysis results indicated the presence of a high TOC content, which originated mainly from alginate and some plant-derived organic matter, whereas bitumen was frequently present in mudstones with thermal maturity in the oil-generation stage. The [Formula: see text] mudstones were comprised mainly of clay minerals, followed by quartz, feldspar, and carbonates. The LPGA-[Formula: see text] experiments revealed the presence of nanoscale slit-shaped pores, and the contribution from mesopores to the total pore volume was the highest in most of the samples. The average pore diameters (APDs) of the mudstone samples were all smaller than 20 nm (4.36–17.79 nm). We determined that there was a clear positive correlation between the APD and the free oil content; however, there were no clear correlations between the APDs and the quartz, carbonate, and TOC contents. FEM studies revealed the presence of intergranular pores with widths of approximately 10 μm, micron-level autogenetic organic matter pores within spores, organic matter pores caused by the hydrocarbon generation effect within organic matter or clay-organic complexes, and intraparticle pores within clays or pyrite framboids. The microlevel intergranular pores might play an important role in shale oil accumulation from source rock of lacustrine origin.