Search

The horizontal distribution and periodic accumulation of hydrocarbon in reservoirs are well understood. However, our understanding on the vertical distribution of hydrocarbon accumulation in reservoirs is not clear and remains mysterious to some extent. We proposed a concept of hydrocarbon accumulation depth limit (HADL) to characterize the hydrocarbon’s vertical distribution in petroliferous basins, which is determined by statistical analyses of the variation trends of reservoir layers’ essential properties, including hydrocarbon saturations (So), movable hydrocarbon ratios (Mo) and dry layer ratio (Ko), when the depth is increased. A total of 80,762 drilling results from 12,237 exploration wells in six representative petroliferous basins in China were collected and analyzed. The reservoir layers’ essential properties So, Mo and Ko and their correlations with porosity, permeability, pore throat radius and thermal evolution degree were investigated. The critical values of So, Mo and Ko that define HADL were quantified to be So=0, Mo=0 and Ko=100. Our study indicates that the HADL in petroliferous basins varies from less than 3,000 m to more than 13,000 m deep, depending on the hydrocarbon composition, reservoir lithology, reservoir age, geothermal gradient, tectonic movement, etc. Two factors play an essential role in the formation and variation of HADL: 1) the depletion of hydrocarbon generation potential of source rocks which cuts off hydrocarbon contribution for reservoirs formation and 2) the termination of differential compaction which eliminates capillary pressure difference between the outer surrounding rocks and inner reservoir layers, ending the dominant driven force for hydrocarbon migration and accumulation in deep and tight reservoir layers. All proven oil reserves of 33.95 billion tons equivalent in China, as well as world’s discovered 52,926 oil and gas reservoirs and their unproved potential resources, are distributed above the HADL we defined.

The Steptoean Positive Carbon Isotope Excursion Event (SPICE) represents one of the largest carbon cycle perturbations in the Cambrian, which coincided with climatic changes and dramatic extinction of shallow-shelf faunas. This carbon perturbation has been linked to a global expansion of marine euxinia (SPICE-OAE), but the precise timing, duration and extent of changing redox conditions across the SPICE event, as well as its influences on the coeval biotic evolution, remain unclear. Here, we report paired δ98Mo–δ238U data across this event, constrained by a radioisotopically anchored astrochronology, based on Alum Shale samples from the Albjära-1 and Billegrav-2 drill-cores in Scandinavia. The δ98Mo profiles are largely invariant around 1.08±0.21‰ with short-term fluctuations parallelling changes in pyritization of iron, possibly as a result of locally varying [H2S]aq in the water column and/or fluctuating reactive iron delivery. The bottom water is interpreted to have been primarily anoxic, but with frequent local variations between oxic and sulfidic conditions in a moderately restricted basin. A novel analytic method based on variation of Mo concentrations at millimeter scale stratigraphic resolution was applied to distinguish between local and global redox signatures, revealing that cyclic redox changes are recorded in the Alum Shale sea with periods of ∼0.3 Myr, ∼0.9 Myr and ∼0.15 Myr before, during and after the SPICE-OAE, respectively. Stratigraphic profiles of Mo, U, Mo/TOC ratios and δ238U in the two cores show comparable trends, facilitating recognition of three chemically distinct stages across the SPICE event: 1) global expansion of marine euxinia (SPICE-OAE; 497.9–496.6 Ma), 2) global contraction of euxinia accompanied by enhanced carbonate weathering inputs (496.6–495.8 Ma) and 3) general global oxygenation (495.8–494.4 Ma). The first in situ correlation between the onset of the SPICE-OAE and the end-Miaolingian extinctions in Baltica corroborates that expansive anoxic and sulfidic water masses likely contributed to the biotic crisis. The time gap between the start of the extinction and the appearance of the new fauna in Baltoscandia is estimated to be ∼600 kyr.

NSO compounds mainly exist in geological bodies in the form of nonhydrocarbons and asphaltenes with abundant geological and geochemical information. Combined with the gas chromatography mass spectrometry (GC-MS) technology, positive-ion electrospray ionization Fourier-transform ion cyclotron resonance MS (FT-ICR MS) was used to understand the composition and distribution characteristics of NSO compounds in the oil sands of the Dongpu Depression and to explore their paleoenvironmental significance. The results show that n-alkanes are characterized by an even carbon number and phytane dominance, suggesting a saline lacustrine environment. Certain abundance of nC37 and β-carotane, high gammacerane content, and low diasterane content are detected in the analyzed samples, reflecting the saline-reducing paleoenvironment for the organic matter. Nine types of heteroatom compounds are detected: N1, N1O1, N1S1, O1, O1S1, O2, O2S1, S1, and S2. The main compounds are S1 and N1 compounds, followed by O1S1 compounds. The double-bond equivalent (DBE) value of S1 compounds is mainly distributed between 3 and 12, and the carbon number is mainly distributed between 18 and 35. The DBE value of N1 compounds is mainly distributed between 4 and 14, and the carbon number is mainly distributed in the range 15-35. Among the S1 compounds, DBE3 compounds (thiophenes) have relatively more sulfur-containing carotenoids (C40). The abundance of C40 S1 and the ratio of pyridine and its homologue DBE4-8/DBE9-12 N1 compounds show a good contrast with the paleoenvironment indicators of gammacerane/C30 hopane and diasterane/regular sterane. They can be used as a reference for the paleoenvironment index. Maturity is another factor affecting the distribution of NSO heteroatoms in the oil sands. NSO compounds are enriched in the DBE area with higher condensation, and the main peak carbon shifts forward. As the maturity increases, the relative abundance of N1 compounds increases, the aromatization intensifies, and carbon is broken into short chains. The research results shed light on the potential application of NSO compounds in petroleum exploration based on FT-ICR MS.

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology. It has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, misconceptions widely exist in studies of different types of petroleum accumulations because of the lack of a unified genetic classification. Unconventional reservoir has been used in the literature as a general name for various oil/gas reservoirs that are formed under complex dynamic mechanisms as long as buoyancy is not the major controlling factor. On the other hand, different terms have been given to the reservoirs even with the same formation mechanism. This paper selected six representative basins in China as the major subject of the study, analyzed the drilling results of 80,762 reservoir layers from 12,237 exploration wells in these basins. By investigating the progress of unconventional oil/gas exploration in North America in the past 30 years and addressing the distribution characteristics of discovered 52,926 oil/gas reservoirs in 1,186 basins around the world, this study revealed the correlations and differences of formation and distribution characteristics between conventional and unconventional oil and gas reservoirs. It was found that there are five correlations between conventional and unconventional reservoirs, including sharing the same oil and gas source, occurring in strata with the same geological age, coexisting in the same sedimentary basins, being confined in the same petroleum systems, and being enriched in the same reservoir layers. It was also found that there are five differences between conventional and unconventional reservoirs, including differences in hydrocarbon compositions, spatial relations to source rocks, reservoir lithology and quality, distribution in geological settings, and reservoir formation mechanism. Then, the unified genetic classification scheme is put forward to clarify their differences and correlations. All kinds of conventional and unconventional oil and gas resource are classified into 3 categories and 6 subcategories according to their dynamic mechanisms of formation, reclassified into 15 types based on main controlling factors, and further divided into 49 styles considering their underground occurrences. The application results show that all different oil/gas reservoirs can find their corresponding positions in the classification scheme, and all the oil/gas reservoirs with the same genetic mechanism, major controlling factor and occurrence can find their particular position in this classification scheme.

The successful development of unconventional hydrocarbons has significantly increased global hydrocarbon resources, promoted the growth of global hydrocarbon production and made a great breakthrough in classical oil and gas geology. The core mechanism of conventional hydrocarbon accumulation is the preservation of hydrocarbons by trap enrichment and buoyancy, while unconventional hydrocarbons are characterized by continuous accumulation and non-buoyancy accumulation. It is revealed that the key of formation mechanism of the unconventional reservoirs is the self-sealing of hydrocarbons driven by intermolecular forces. Based on the behavior of intermolecular forces and the corresponding self-sealing, the formation mechanisms of unconventional oil and gas can be classified into three categories: (1) thick oil and bitumen, which are dominated by large molecular viscous force and condensation force; (2) tight oil and gas, shale oil and gas and coal-bed methane, which are dominated by capillary forces and molecular adsorption; and (3) gas hydrate, which is dominated by intermolecular clathration. This study discusses in detail the characteristics, boundary conditions and geological examples of self-sealing of the five types of unconventional resources, and the basic principles and mathematical characterization of intermolecular forces. This research will deepen the understanding of formation mechanisms of unconventional hydrocarbons, improve the ability to predict and evaluate unconventional oil and gas resources, and promote the development and production techniques and potential production capacity of unconventional oil and gas.

The discovery and large-scale exploration of unconventional oil/gas resources since 1980s have been considered as the most important advancement in the history of petroleum geology; that has not only changed the balance of supply and demand in the global energy market, but also improved our understanding of the formation mechanisms and distribution characteristics of oil/gas reservoirs. However, what is the difference of conventional and unconventional resources and why they always related to each other in petroliferous basins is not clear. As the differences and correlations between unconventional and conventional resources are complex challenging issues and very critical for resources assessment and hydrocarbon exploration, this paper focused on studying the relationship of formations and distributions among different oil/gas reservoirs. Drilling results of 12,237 exploratory wells in 6 representative petroliferous basins of China and distribution characteristics for 52,926 oil/gas accumulations over the world were applied to clarify the formation conditions and genetic relations of different oil/gas reservoirs in a petroliferous basin, and then to establish a unified model to address the differences and correlations of conventional and unconventional reservoirs. In this model, conventional reservoirs formed in free hydrocarbon dynamic field with high porosity and permeability located above the boundary of hydrocarbon buoyancy-driven accumulation depth limit. Unconventional tight reservoirs formed in confined hydrocarbon dynamic field with low porosity and permeability located between hydrocarbon buoyancy-driven accumulation depth limit and hydrocarbon accumulation depth limit. Shale oil/gas reservoirs formed in the bound hydrocarbon dynamic field with low porosity and ultra-low permeability within the source rock layers. More than 75% of proved reserves around the world are discovered in the free hydrocarbon dynamic field, which is estimated to contain only 10% of originally generated hydrocarbons. Most of undiscovered resources distributed in the confined hydrocarbon dynamic field and the bound hydrocarbon dynamic field, which contains 90% of original generated hydrocarbons, implying a reasonable and promising area for future hydrocarbon explorations. The buried depths of hydrocarbon dynamic fields become shallow with the increase of heat flow, and the remaining oil/gas resources mainly exist in the deep area of “cold basin” with low geothermal gradient. Lithology changing in the hydrocarbon dynamic field causes local anomalies in the oil/gas dynamic mechanism, leading to the local formation of unconventional hydrocarbon reservoirs in the free hydrocarbon dynamic field or the occurrence of oil/gas enrichment sweet points with high porosity and permeability in the confined hydrocarbon dynamic field. The tectonic movements destroy the medium conditions and oil/gas components, which leads to the transformation of conventional oil/gas reservoirs formed in free hydrocarbon dynamic field to unconventional ones or unconventional ones formed in confined and bound hydrocarbon dynamic fields to conventional ones.

A vital factor influencing shale oil exploration in lacustrine shale reservoirs is oil mobility, which is closely associated with the shale pore structure and fluid properties, especially for the l...

Hydrocarbon expulsion occurs only when pore fluid pressure due to hydrocarbon generation in source rock exceeds the force against migration in the adjacent carrier beds. Taking the Middle–Upper Ordovician carbonate source rock of Tarim Basin in China as an example, this paper proposes a method that identifies effective carbonate source rock based on the principles of mass balance. Data from the Well YW2 indicate that the Middle Ordovician Yijianfang Formation contains effective carbonate source rocks with low present-day TOC. Geological and geochemical analysis suggests that the hydrocarbons in the carbonate interval are likely self-generated and retained. Regular steranes from GC–MS analysis of oil extracts in this interval display similar features to those of the crude oil samples in Tabei area, indicating that the crude oil probably was migrated from the effective source rocks. By applying to other wells in the basin, the identified effective carbonate source rocks and non-source rock carbonates can be effectively identified and consistent with the actual exploration results, validating the method. Considering the contribution from the identified effective source rocks with low present-day TOC (TOCpd) is considered, the long-standing puzzle between the proved 3P oil reserves and estimated resources in the basin can be reasonably explained.

Thermal maturation in the shale oil/gas system is inherently complex due to the competitive interplays between hydrocarbon generation and retention processes. To study hydrocarbon generation characteristics from shales within different stages of thermal maturation under the influence of retained oil, we performed Micro-Scale Sealed Vessels (MSSV) pyrolysis on a set of artificially matured lacustrine shale samples from the Shahejie Formation in the Dongpu Depression in Bohai Bay Basin, China. Experimental results show that hydrocarbon yields of shale samples with or without retained oil at various thermal maturities follow different evolution paths. Heavy components (C15+) in samples crack at high temperatures and generally follow a sequence, where they first transform into C6–14 then to C2–5 and C1. Methane accounts for most of the gaseous products at high temperatures in all samples, with different origins. The cracking of C2–5 is the main methane-generating process in samples with retained oil, whereas the source of methane in samples without retained oil is kerogen. In the studied shales, retained oils at early-mature stage retard the transformation of liquid to gaseous hydrocarbon and prompt the cracking of C2–5 to C1 to some extent. TSR reaction related to gypsum in the studied samples is the primary reason that can explain the loss of hydrocarbon yields, especially at high temperatures. In addition, transformation of volatile hydrocarbons to gas and coke also accounts for the loss of generated hydrocarbon, as a secondary factor.

This study proposes a new method for estimating tight oil resources in a closed petroleum system using an alternative mass balance model. The proposed approach primarily derives resource estimates based on a large volume of Rock-Eval pyrolysis data. In addition to leveraging the cost-effective, straightforward, and rapid process, the proposed method has the flexibility to assess the potential of different types of resources, including organic-rich tight (shale) oil and organic-lean tight oil. The method is validated by assessing the oil resource potential of the middle Permian Lucaogou Formation (P2l) in the Jimusaer depression, Junggar Basin, China. Results indicate that the P2l contains 1.62 × 109 t (11.91 × 109 bbl) of organic-rich and 2.88 × 109 t (21.17 × 109 bbl) of organic-lean tight oil. Of the organic-rich tight oil, 21% comprises free oil resources, amounting to 0.343 × 109 t (2.521 × 109 bbl). The proposed approach deals sufficiently with the different resources in a petroleum system well and provides a useful tool for estimating the resource potential of an unconventional play.

The reservoir properties, diagenetic features and evolution of the Paleogene Shahejie Formation (Es) in the Nanpu sag, Bohai Bay Basin were analyzed based on mineralogical and petrological data, and the main controlling factors and formation mechanisms of medium to deep high-quality reservoir were revealed by multiple regression analysis. The results show that the sedimentary microfacies, rigid grains content, and dissolution process are the key factors controlling the formation of high-quality clastic reservoir in middle to deep depth in the Nanpu sag. The formation mechanisms of middle to deep sandstones of the Es in different structural belts differ widely in formation mechanism. The Es1 (uppermost member of Es) sandstone reservoirs in the Nanpu No.3 structural belt is low porosity, moderate to high permeability reservoir in the mesodiagenesis A2 stage on the whole, and the formation of high-quality reservoirs is mainly attributed to strong compaction resistance ability primarily, and dissolution process secondarily. The Es3 (third member of Es) sandstones in Gaoshangpu structural belt is classified as tight sandstones in the mesodiagenesis A1 stage, in which the development of favorable reservoirs is primarily controlled by dissolution. This study provides references for reservoir evaluation of deep clastic reservoirs and exploration deployment in the Bohai Bay rift basin. As there are high-quality reservoirs, it is believed that the deep clastic reservoirs in the eastern of China, such as Bohai Bay Basin still have significant exploration potential. Key words: middle to deep clastic reservoir, high-quality reservoir, diagenetic evolution, Nanpu sag, Bohai Bay Basin, Shahejie Formation

In order to make accurate decisions in interpreting depositional environments of sedimentary rocks, a multi-proxy approach is best employed. In the Middle Cambrian Lower Zhangxia Formation exposed at Xiaweidian in the Northern China, lack of this form of approach puts doubts on the various models (e.g. carbonate ramp and isolated platform) proposed by previous workers. In this study, we integrated field outcrop investigation with laboratory examinations of thin sections with light and electron microscopies to further understand sedimentary environments of the Lower Zhangxia Formation. Dominant rock types of this formation include oolitic limestone, muddy limestone, flat-pebble limestone and calcareous mudstone. Evidence from ooid features and lime-mud content of oolitic limestones suggests their deposition in an environment with intermittent high energy level. The muddy limestones were formed on a restricted platform with lower wave energy, which is supported by the existence of pyrites in a reducing environment and the input of terrestrial clays from neighboring clastic environments. The flat-pebble limestones were formed by storm reworking of early deposits on restricted platform below a fair-weather wave base, due to their composition and clast features. Mudstones with occurrences of terrestrial silts could be associated with clastic shallow marine adjacent to the restricted platform. A mixed carbonate-clastic depositional model is suggested for this formation and can be used as model for other researchers working in the North China. Cited as : Zhang, X., Pang, X., Jin, Z., Hu, T., Toyin, A., Wang, K. Depositional model for mixed carbonate-clastic sediments in the Middle Cambrian Lower Zhangxia Formation, Xiaweidian, North China. Advances in Geo-Energy Research, 2020, 4(1): 29-42, doi: 10.26804/ager.2020.01.04

The fine-grained rocks in the Paleogene Shahejie Formation in Nanpu Sag, Huanghua Depression, Bohai Bay Basin, are extremely important source rocks. These Paleogene rocks are mainly subdivided into organic-rich black shale and gray mudstone. The average total organic carbon contents of the shale and mudstone are 11.5 wt.% and 8.4 wt.%, respectively. The average hydrocarbon (HC)-generating potentials (which is equal to the sum of free hydrocarbons (S1) and potential hydrocarbons (S2)) of the shale and mudstone are 39.3 mg HC/g rock and 28.5 mg HC/g rock, respectively, with mean vitrinite reflectance values of 0.82% and 0.81%, respectively. The higher abundance of organic matter in the shale than in the mudstone is due mainly to paleoenvironmental differences. The chemical index of alteration values and Na/Al ratios reveal a warm and humid climate during shale deposition and a cold and dry climate during mudstone deposition. The biologically derived Ba and Ba/Al ratios indicate high productivity in both the shale and mudstone, with relatively low productivity in the shale. The shale formed in fresh to brackish water, whereas the mudstone was deposited in fresh water, with the former having a higher salinity. Compared with the shale, the mudstone underwent higher detrital input, exhibiting higher Si/Al and Ti/Al ratios. Shale deposition was more dysoxic than mudstone deposition. The organic matter enrichment of the shale sediments was controlled mainly by reducing conditions followed by moderate-to-high productivity, which was promoted by a warm and humid climate and salinity stratification. The organic matter enrichment of the mudstone was less than that of the shale and was controlled by relatively oxic conditions.

The third member of the Upper Triassic Xujiahe Formation (T3x3) is a typical source-reservoir-cap unit for natural gas exploration in the Sichuan Basin. However, most previous studies mainly focused on the T3x3 as a source rock, ignoring its role as a reservoir. As a result, the evaluation of hydrocarbon resource potential was not accurate. This study established a hydrocarbon generation and expulsion model through analyzing the geological and geochemical characteristics of the T3x3 source rocks, and calculated the resource potential of conventional gas, tight gas and shale gas systematically with combining the lower boundary of buoyancy-dominated accumulation (LBBA). The results indicated that the thickness of the source rocks dominated by mudstone was distributed widely, with an average value of more than 45 m. The sedimentary environment was salty lacustrine deposits. They have a high content of total organic carbon (TOC) with an average value of 4.80 wt%, the kerogen is mainly type III with minor type II, and the thermal evolution has entered the high to over mature stage. The hydrocarbon generation threshold was determined to be 0.5%Ro, while the hydrocarbon expulsion threshold and the LBBA were determined to be 0.83%Ro and 1.12%Ro, respectively. The efficiency of hydrocarbon expulsion was relatively high, with an average of about 56%. Also, the maximum hydrocarbon generation and expulsion intensity reached to 110 × 108 m3/km2 and 53 × 108 m3/km2. The amounts of hydrocarbon generation, expulsion and residual associated with the T3x3 source rocks were 125.68 × 1012m3, 70.38 × 1012m3, and 55.30 × 1012m3, respectively. Under the criterion condition of the LBBA, the conventional gas resource was 7.21 × 1010m3, the tight gas resource was 294.34 × 1010m3, and the shale gas resource was 2488.50 × 1010m3. It indicated good prospects for exploration.

Mineralogical, petrographical, geochemical analyses, and fluid inclusions petrography and microthermometry were combined to investigate the basic properties of the source rock (organic matter content, kerogen type, and thermal maturity) and sandstone reservoirs (composition, pore systems, porosity, and permeability), the hydrocarbon origin, and the formation mechanisms of the deep (>3.5 km) petroleum system in the Upper Paleogene Es1 (the uppermost member of the Shahejie Formation) in the No. 3 Structural Belt in the Nanpu Sag, Bohai Bay Basin. The results indicate that the Es1 source rock is primarily composed of dark gray mudstone and presents a set of high-quality source rocks (>500 m, average total organic carbon (TOC) 1.38%, in a mature stage (maximum pyrolysis yield of 430 °C–460 °C)). The Es1 sandstone is composed of lithic arkose formed in a braided river delta and has low porosity (average 13.4%) but moderate-high permeability (average 184.9 mD). The hydrocarbons originated from the Es1 source rocks in the Caofeidian subsag during two charging periods: 10 Ma and 3 Ma. The key factors controlling the formation of the deep petroleum system are as follows: (a) High-quality hydrocarbon supply, (b) Medium-high permeability reservoirs, (c) A favorable configuration of the source rock and reservoirs (self-generated and self-accumulated), and (d) Late hydrocarbon charging; the second factor is the most important. The medium-high permeability reservoirs are attributed to a high-energy depositional environment (distributary channels of braid delta front), a high content of rigid detrital grains (mainly quartz and metamorphic rock fragments) provided by the Archean granite provenance, and the secondary pores formed by feldspar dissolution. This study provides a new example for revealing the formation mechanisms of deep (>3.5 km) petroleum systems in the terrestrial rift basin across the Bohai Bay Basin.

Superimposed basins are commonly characterized by a complex distribution of oil and gas accumulations. Because they have generally experienced multistage hydrocarbon accumulation and tectonic movement, it is challenging to predict favorable exploration zones in these basins. The exploration of the deep strata of the Sichuan Basin (i.e., a typical superimposed basin), West China, has been unsatisfactory for petroleum prospectors. Therefore, we chose the Cambrian Longwangmiao Formation in the Sichuan Basin as an example to demonstrate the method, i.e., combination of petroleum system elements to quantitatively predict the petroleum favorable exploration zones. Based on the detailed analysis of the hydrocarbon accumulation process, the source rock (S), migration (M), reservoir depositional facies (D), and regional cap rock (C) are the most important elements controlling the formation and distribution of oil and gas accumulations in the studied basin. By studying the functional relationships among these four elements and the distribution of the petroleum accumulations, we determined the accumulation probability related to each element and quantitatively predicted the probability of a favorable hydrocarbon accumulation zone. We built a quantitative model of the reservoir preservation probability based on the statistical relationship between the intensity of the tectonic movement and subsequent destruction of existing oil and gas accumulations. Favorable exploration zones can be determined by overlaying favorable accumulation zones with disturbances associated with the tectonic evolution. The results suggest that the most favorable exploration zones of the Longwangmiao Formation in the Sichuan Basin are distributed in the regions west of Weiyuan and east of Gaoshiti–Moxi, Pengxi–Yilong, and Dazhou–Kaijiang. The production data for existing fields in the Sichuan Basin show that 87% of the successful wells are in the predicted favorable exploration zones and that the success rate with respect to the prediction of failure wells is 67%. This approach highlights the most prospective exploration areas in superimposed basins, which, in general, is challenging and complex for traditional basin modeling tools.

The genetic type and accumulation model of the Devonian reservoirs in the Marsel Block remain unclear, despite decades of exploration history. According to the well testing, logging interpretations and sample testing results, the Devonian natural gas reservoir in the Marsel Block has five typical characteristics: (1) It is obvious that the traps contain continuous gas accumulations. Not only the apexes of the structures are enriched in natural gas, but also the slopes and depressions contain gas accumulations. (2) The gas reservoirs are classified as tight reservoirs, but there are also reservoirs with high porosity and permeability in some areas. (3) The general negative or low-pressure in the gas reservoir is obvious, although the pressure in the target layers of some wells is close to normal. (4) The yields of single wells in the Devonian reservoir are quite different: some wells have low yields or are dry, whereas the gas production from high-yield wells has reached 700 000 m3/day. (5) The gas-water relationship is complicated: there is no obvious gas-water interface, but the water-producing layer is generally located at the apexes of structures. Research and analysis have shown that using the model of the conventional gas reservoirs genetic type can only explain the characteristics of parts of the gas reservoir, while the model of accumulation in a deep-basin gas reservoir cannot fully explain the distribution characteristics of the Devonian reservoir. However, the model of accumulation in a stacked complex continuous oil and gas reservoir can reasonably explain the geological and distribution characteristics of the Devonian reservoir. Moreover, the predicted gas distribution along a cross-section of the reservoir is also in agreement with the geological background and tectonic environment of the Marsel Block, therefore, the genetic type of the Devonian natural gas reservoir in the Marsel Block is a stacked complex continuous tight-gas reservoir. Finally, by comprehensively analyzing the source rock, reservoir and cap rocks, as well as the structural characteristics, it is verified that Devonian in the Marsel Block has favorable geological conditions for formation of a superimposed continuous tight gas reservoir.