Hydrocarbon Generation Center Research Articles

Geological characteristics and developmental achievements of the large presalt carbonate gas fields in the Amu Darya Basin

The Amu Darya Basin accounts for one of the most abundant natural gas resources globally, it is the main gas supplier to the Central Asian natural gas pipeline. It also holds potential for the natural gas exploration and development. Within this basin, valuable Jurassic carbonate rocks and gypsum-salt-gas-bearing combinations are developed. These include the presalt transitional Middle and Lower Jurassic coal-bearing source rocks, which provide sufficient gas sources, and the Middle and Upper Jurassic reef-shoal carbonate and gypsum salts, forming an effective reservoir–caprock combination. The unique geological configuration forms optimal accumulation conditions for natural gas in the high-energy sedimentary-facies belt of the carbonate platform which controlled by the coal-bearing gas-generation center and large basement ancient uplift area. Large natural gas fields are mainly distributed in the presalt Jurassic carbonate rocks, driven by high-quality hydrocarbon-generation centers, ancient uplift backgrounds, and ultrathick gypsum-salt rocks. While large gas fields have been discovered in large structural traps at the center of the depressions, exploration potential is still remains in the vast area with a burial depth exceeding 4500 m. These make the basin a key area for further exploration. The Amu Darya Right Bank Block located in the northeast of the basin, which has seen 15 years of rapid and efficient exploration and development by PetroChina, has discovered three gas field groups, each contains 2 billion m3 of gas: the western intraplatform shoal, central gently sloping reef beach, and Eastern thrust structure, fracture-cave-type gas field groups. PetroChina has achieved a production capacity of 14 billion cubic meters. In response to the geological and developmental characteristics of the three gas field groups, tailored development strategies have been formulated. The strategies are based on the integrated concept of geological and developmental engineering. Optimization efforts have been made in well pattern deployment, including highly deviated wells, as well as the design of gas field pressurization engineering. In addition, comprehensive evaluations have been conducted, taking the stable production period, water-avoidance distance, and investment considerations into account. The efforts aim to support the project of transforming the Amu Darya River into a model for the efficient development of the “Belt and Road” energy cooperation project.

Oil and gas complexes as a material expression of geofluid dynamic systems

The purpose of the present research is to analyze the geofluid dynamic concept of oil and gas formation. The research uses the author's data on the structure, composition and thickness of multi-aged oil and gas complexes of the Siberian platform (Russia). The oil and gas complexes identified as a result of the integrated geological, geochemical and geophysical studies carried out under oil and gas geological zoning and operational work are presented as a material expression of geofluid dynamic systems. Any geofluid dynamic system includes hydrocarbon generation centers, oil and gas migration routes, types of reservoirs and traps, lithological composition of reservoir rocks and reservoir cap rocks Also it is controlled by a favorable combination of their appearance in geological time and space. An ordinary fluid dynamic system is presented by hydrocarbon solutions generated by oil and gas generation centers, which are examples of a trivial defluidization of oil and gas source rocks of a sedimentary basin. This study allowed to be the first who has identified the elements of multi-age geofluid dynamic systems, presented their material expression in the form of multi-age oil and gas bearing complexes as well as analyzed the composition of hydrocarbons on the example of individual deposits of variousoil and gas-bearing areas. Besides, possible generation centers of hydrocarbon fluids and ways of their migration were investigated. Oil fields of different ages of the oil and gas bearing provinces of the Siberian Platform feature different composition and density, whereas according to numerous available data, they belong to a single genetic type, which is characterized by the predominance of methane hydrocarbons.

Tectonic evolution and its control on oil–gas accumulation in southern East China Sea since the Jurassic

Based on the results from the previous research on Mesozoic igneous rocks, as well as tectonic environments in the northern South China Sea and southern East China Sea (NSCS-SECS), geophysical parameters, strata, and characteristics of seismic facies in NSCS-SECS were investigated. These findings were combined with results from the analysis of the balanced profile evolution to re-evaluate the tectonic evolution of SECS since the Jurassic. Furthermore, burial history and simulation of wells in the SECS were analyzed using well, seismic and source rock data. Furthermore, favorable models of oil–gas accumulation in the Lower–Middle Jurassic were proposed in combination with studies on elements and conditions of the petroleum system. The results demonstrated that the NSCS-SECS had consistent tectonic settings and comparable strata from the Jurassic to the Cretaceous time. There was a large unified basin in this period. The basin experienced two evolutionary stages, respectively, the fore-arc depression basin in the Early–Middle Jurassic (J1-2) and the back-arc faulted basin in the Late Jurassic–Cretaceous (J3-K). There was considerable deposition of dark mudstones in the SECS during the Lower–Middle Jurassic. The Keelung Sag was the depositional center accumulating the thickest section of the Lower–Middle Jurassic source rocks which entered a high-maturity stage. Hence, it was the hydrocarbon generation center in the SECS. The process of generating hydrocarbons from Lower–Middle Jurassic source rocks was of high complexity from northwest to southeast. The Lower–Middle Jurassic source rock at the northwest edges of the basin experienced two hydrocarbon generation stages, while the Keelung Sag toward the southeast experienced three hydrocarbon generation stages. The models and types of oil–gas accumulation in various evolutionary phases were different due to the control by tectonic evolution. Oil and gas that were generated by Lower–Middle Jurassic source rocks in the Keelung Sag migrated and accumulated in the western high-tectonic units. Research findings provide insights into Mesozoic oil and gas exploration in the NSCS-SECS.

North slope transition zone of Songnan-Baodao sag in Qiongdongnan Basin and its control on medium and large gas fields, South China Sea

Based on analysis of newly collected 3D seismic and drilled well data, the geological structure and fault system of Baodao sag have been systematically examined to figure out characteristics of the transition fault terrace belt and its control on the formation of natural gas reservoirs. The research results show that the Baodao sag has the northern fault terrace belt, central depression belt and southern slope belt developed, among them, the northern fault terrace belt consists of multiple transition fault terrace belts such as Baodao B, A and C from west to east which control the source rocks, traps, reservoirs, oil and gas migration and hydrocarbon enrichment in the Baodao sag. The activity of the main fault of the transition belt in the sedimentary period of Yacheng Formation in the Early Oligocene controlled the hydrocarbon generation kitchen and hydrocarbon generation potential. From west to east, getting closer to the provenance, the transition belt increased in activity strength, thickness of source rock and scale of delta, and had multiple hydrocarbon generation depressions developed. The main fault had local compression under the background of tension and torsion, giving rise to composite traps under the background of large nose structure, and the Baodao A and Baodao C traps to the east are larger than Baodao B trap. Multiple fault terraces controlled the material source input from the uplift area to form large delta sand bodies, and the synthetic transition belt of the west and middle sections and the gentle slope of the east section of the F12 fault in the Baodao A transition belt controlled the input of two major material sources, giving rise to a number of delta lobes in the west and east branches. The large structural ridge formed under the control of the main fault close to the hydrocarbon generation center allows efficient migration and accumulation of oil and gas. The combination mode and active time of the main faults matched well with the natural gas charging period, resulting in the hydrocarbon gas enrichment. Baodao A transition belt is adjacent to Baodao 27, 25 and 21 lows, where large braided river delta deposits supplied by Shenhu uplift provenance develop, and it is characterized by large structural ridges allowing high efficient hydrocarbon accumulation, parallel combination of main faults and early cessation of faulting activity, so it is a favorable area for hydrocarbon gas accumulation. Thick high-quality gas reservoirs have been revealed through drilling, leading to the discovery of the first large-scale gas field in Baodo 21-1 of Baodao sag. This discovery also confirms that the north transition zone of Songnan-Baodao sag has good reservoir forming conditions, and the transition fault terrace belt has great exploration potential eastward.

Rift-uplift-depression accumulation-controlling models of the large gas province in Cambrian pre-salt, Tarim Basin, China

The Cambrian pre-salt has the accumulation conditions for forming a compound large gas province and was the strategic replacement area with the lowest exploration level and the largest exploration potential in the Tarim Basin. However, no significant discoveries have been found in the exploration for many years. The key problem is that the unclear controlling factors and spatial distribution of the hydrocarbon generation center and scale beach reservoir result in the ambiguity of favorable exploration directions and zones. Given this, a comprehensive application of seismic, drilling, well-logging, mud-logging, and geochemical data has been carried out to study the source-controlling, reservoir-controlling, caprock-controlling, and accumulation-controlling of the Cambrian pre-salt area, constructing the accumulation-controlling model and defining the favorable zones and exploration breakthrough direction. The following points have been gained: (1) Paleo-rifts controlled hydrocarbon generation center. The rift-depression structure formed in the Nanhua System to Sinian System provided the structural background for the development of the Lower Cambrian and controlled the deposition of the Cambrian Yuertusi Formation. In the negative tectonic area controlled by rifting, the thickness of the Yuertusi Formation was large and formed the hydrocarbon generation center. (2) The paleo-uplifts controlled the development of beach facies dolomite reservoir. The paleo-uplifts formed simultaneously with the Nanhua System paleo-rifts controlled the development and distribution of high-energy beaches in the Xiaerbulake Formation, and large-scale dolomitic beach facies reservoirs were formed on both sides of the Tanan paleo-uplift. (3) The paleo-depression controlled the development of gypsum-salt caprock. In the Middle and Late Cambrian, the Taxi platform has closed and formed a strong evaporation environment, while a wide-covering gypsum-salt caprock was deposited in the unified depression within the platform due to the development of the Luntai-Gucheng near the north-south rimmed platform margin. (4) The time-space matching of rift-uplift-depression controlled the formation and distribution of oil and gas. Three types of accumulation-controlling models, the stable rift-uplift-depression, the active rift-uplift-depression, and the transitional rift-uplift-depression, were established, indicating the stable and transitional areas as the main exploration directions, and the Aman low uplift between Awati Sag and Manxi Sag as the preferred target area for the large gas province in Cambrian pre-salt.

The sorting effect of hydrodynamics on the geochemical compositions of sedimentary organic matter in a lacustrine rift basin: Significance for hydrocarbon exploration on the Qibei slope, Bohai Bay Basin, China

Hydrodynamic sorting exerts a first-order control on the quantity, type and molecular composition of sedimented organic matter. Although this physical mechanism has been invoked to explain the varying content and composition of organic matter in global continental margin sediments, it is rarely mentioned in the interpretation of the heterogeneity of source rocks in petroliferous basins. We investigate the controls of hydrodynamic sorting on the differentiation of organic matter content, type and molecular composition, and on the hydrocarbon generation capacity of source rocks in the lower part of the first member of the Eocene Shahejie Formation in the Qibei slope of the Bohai Bay Basin, by using the Rock-Eval pyrolysis, gas chromatography-mass spectrometry and logging interpretation tools. The source rock samples in the northeastern part of the slope generally present a relatively coarse grain size, less organic matter content, and are rich in humic material, whereas the source rocks in the southwestern slope area show opposite trends in these characteristics. Biomarker data demonstrate reducing sedimentary conditions and that the proportion of organic matter input from aquatic organisms versus terrestrial higher plants increases with a reduction in grain size. Pyrolysis data with a hydrogen index model shows that this organic matter-grain size relationship causes a difference in hydrocarbon generation capacity of the source rocks in various regions of the slope. This relationship also plays a role in a migration of the hydrocarbon generation center from a low-lying area in the northeastern slope to a relatively higher area in the southwest. In summary, hydrodynamic sorting is important in the distribution of organic matter pools in the slope area, causing changes in the abundance, type and composition of organic matter in the source rocks in the slope area and profoundly affecting the overall pattern of hydrocarbon generation.

Control of the Cretaceous Paleofluid Potential on the Source-Distal Lithologic Reservoirs in the Western Tabei Area of the Tarim Basin

The Cretaceous clastic oil and gas reservoirs in the western Tabei area of the Tarim Basin are far away from source rocks (source-distal), and the hydrocarbons mainly originate from Triassic continental source rocks in the northern Kuqa Depression. Early exploration focused on structural oil and gas reservoirs, and yet, with deepening of exploration practice, exploration has shifted from structural oil and gas reservoirs to lithologic reservoirs. In such context, under guidance of the theory of migration and accumulation for source-distal reservoirs, the key accumulation period of Triassic source rocks is determined, and the migration path of oil and gas is clarified. According to the geological characteristics of the study area, the impression method and sequence ratio method are used to restore the paleoburial depth, and the Fillippone formula is used to restore the paleopressure. Based on Hubbert’s theory, the paleofluid potential field of Triassic oil and gas in the Neogene Kangcun period is reasonably reconstructed. These combined with the planar structural evolution of Cretaceous reveal the preferential source-distal migration paths and directions of oil and gas. The favorable area of oil and gas accumulation is demarcated, and then, the facies belts with favorable lithology have been identified. The research results show the following: (1) The hydrocarbons of the Cretaceous oil and gas reservoirs originate from the Triassic source rocks. The Neogene Kangcun period is the key accumulation period. Hydrocarbons migrate to the western Tabei area along the Cretaceous basal unconformities and Late Yanshanian faults. (2) The paleofluid potential field of the Cretaceous during the key accumulation period shows the characteristics of “being high in the north and low in the south,” which is consistent with the gradual decrease of fluid potential along the migration distance from the northern hydrocarbon generation center (Kuqa Depression) to the south slope, and coincides with the main distribution range of source rocks in the Kuqa Depression. On the basis of the aforementioned, four preferential source-distal migration paths and directions of hydrocarbons have been clarified, and the Yudong-Yingmaili area is confirmed as a favorable area for the source-distal migration and accumulation of hydrocarbons into the Cretaceous. (3) In terms of the favorable areas for source-distal oil and gas migration and accumulation to Cretaceous strata, the forward distal end and lateral flanks of the branched retrogradational delta are the favorable facies belts for the next exploration of lithologic oil and gas resources. The recent breakthroughs in the lithologic reservoirs of wells D7 and M46 have confirmed that the findings of this research on the preferential source-distal migration paths and accumulation positions of hydrocarbons are of great guiding values for exploration deployment of Cretaceous lithologic reservoirs far away from source rocks.

Paleotemperature modeling of hydrocarbon generation centers and their role in the formation of «Paleozoic» oil deposits (Ostaninskoe field, Tomsk region)

Study and exploration of the pre-Jurassic oil and gas complex in Western Siberia is one of the aspects of hydrocarbon raw-material base development. The main scope of this study is to locate the source of Paleozoic hydrocarbons. The problem of modeling and assessing the role of Paleozoic-Mesozoic hydrocarbon generation centers in the formation of «Paleozoic» oil deposits in the section of the Ostaninskoe oil and gas condensate field (Tomsk region) is solved. In the formation of the oil and gas content of the pre-Jurassic basement two reservoirs are involved: the weathering crust and the roof of the bed-rock Paleozoic. The first was formed during the period of 213–208 Ma, and the second is genetically determined by epigenetic processes in the weathering crust. Potential hydrocarbon sources for the weathering crust and bed-rock Paleozoic reservoirs are Domanic type rocks in the crystalline basement: Larinskaya S1lr, Mirnaya D1mr, Chuzikskaya D2cz, Chaginskaya D3cg Formations, as well as Tyumenskaya J1-2tm and Bazhenovskaya J3bg Formations in sedimentary cover. To perform joint paleotemperature modeling of sedimentary basins of the «modern» Jurassic-Cretaceous and Paleozoic «paleobasins», the Ostaninskaya 438P well was selected, which is due to the presence of measured temperatures both in the Jurassic sections and in the pre-Jurassic formations, as well as fluid inflows from the pre-Jurassic horizons into the well. At the first step, the solution of the inverse problem of geothermics was obtained using reservoir temperatures and vitrinite reflectance measurements from the Mesozoic deposits: density of deep heat flow from the base of sedimentary section was determined, which is characterized by a quasi-constant value from the Jurassic to the present. The second step was to solve the inverse problem using vitrinite reflectance measurements from Paleozoic sediments. As a result, the heat flow value was obtained for the key moments of geodynamic history of the stratigraphic section, starting from the Silurian. By solving direct problems of geothermics with the given values of heat flow, the structural-tectonic and thermal history of four Paleozoic potential oil source formations (as well as Jurassic – Bazhenov and Tyumen Formations) has been retraced. The controversial aspects of the heat transfer model in the section of the Ostaninskoe field are considered. It has been established that the Tyumen and Bazhenov oil sources (most likely Bazhenov) are syngenetic (in terms of generation, accumulation and preservation time) for the weathering crust and the Paleozoic reservoirs. The role of the Chaginskaya Formation as gas source is insignificant.

Geological conditions, reservoir evolution and favorable exploration directions of marine ultra-deep oil and gas in China

By analyzing the structural background, petroleum geological conditions, and typical regional (paleo) oil and gas reservoirs in marine ultra-deep oil and gas regions in China, this paper reveals the evolution processes of the marine ultra-deep oil and gas reservoirs and the key controlling factors of accumulation. The marine ultra-deep oil and gas resources in China are buried at depth of greater than 6000 m, and are mainly distributed in the Precambrian and Lower Paleozoic strata in the Sichuan, Tarim and Ordos cratonic basins. The development of marine ultra-deep source rocks in China is controlled by cratonic rifts and cratonic depressions with the background of global supercontinent breakup-convergence cycles. The source rocks in Sichuan Basin have the most developed strata, followed by Tarim Basin, and the development strata and scale of Ordos Basin needs to be further confirmed. The marine ultra-deep reservoir in China is dominated by carbonate rocks, and the reservoir performance is controlled by high-energy sedimentary environment in the early stage, superimposed corrosion and fracture in the later stage. The regional caprocks are dominated by gypsum salt rocks, shale, and tight carbonate rock. The ultra-deep oil and gas fields in China have generally experienced two stages of oil-reservoir forming, cracking (or partial cracking) of paleo-oil reservoirs, and late finalization of cracked gas (or highly mature to over mature oil and gas). The oil and gas accumulation is controlled by static and dynamic geological elements jointly. Major hydrocarbon generation center, high quality and large-scale reservoir resulted from karstification of high energy facies belt, thick gypsum rock or shale caprock, and stable trapping and preservation conditions are the key factors for accumulation of ultra-deep oil and gas. We propose three favorable exploration directions, i.e. the areas around intracratonic rift and intracratonic depression, and craton margin.

Evaluation of Hydrocarbon Generation Using Structural and Thermal Modeling in the Thrust Belt of Kuqa Foreland Basin, NW China

The Kuqa Basin is a typical foreland basin in northwest China, characterized by compressive foreland fold-and-thrust belts and a regionally distributed huge salt layer. A large number of overthrust faults, fault-related folds, and salt-related structures are formed on the thrust belt due to strong compression and structural deformation, causing difficulty in simulation of the basin. In this study, modeling of the thermal history of the complicated compressional structural profiles in the Kuqa foreland basin was successfully conducted based on the advanced “Block” function introduced by the IES PetroMod software and the latest geological interpretation results. In contrast to methods used in previous studies, our method comprehensively evaluates the influence of overthrusting, a large thick salt layer with low thermal conductivity, fast deposition, or denudation on the thermal evolution history. The results demonstrate that the hydrocarbon generation center of the Kuqa foreland basin is in the deep layers of the Kelasu thrust belt and not in the Baicheng Sag center, which is buried the deepest. A surprising result was drawn about the center of hydrocarbon generation in the Kuqa foreland basin, which, although not the deepest in Baicheng Sag, is the deepest part of the Kelasu thrust Belt. In terms of the maturity of the source rock, there are obvious temporal and spatial differences between the different structural belts in the Kuqa foreland basin, such as the early maturation of source rocks and the curbing of uplift and hydrocarbon generation in the piedmont zone. In the Kelasu thrust belt, the source rock made an early development into the low mature-mature stage and subsequently rapidly grew into a high-over mature stage. In contrast, the source rock was immature at an early stage and subsequently grew into a low mature-mature stage in the Baicheng Sag–South slope belt. The time sequence of the thermal evolution of source rocks and structural trap formation and their matching determines the different accumulation processes and oil and gas compositions in the different structural belts of the Kuqa foreland basin. The matching of the multistage tectonic activity and hydrocarbon generation determines the characteristics of the multistage oil and gas accumulation, with the late accumulation being dominant. The effective stacking of the gas generation center, subsalt structural traps, reservoir facies of fine quality, and huge, thick salt caprocks creates uniquely favorable geological conditions for gas enrichment in the Kelasu foreland thrust belt.

Development and distribution rules of the main Neoproterozoic source and reservoir strata in the Yangtze Block, Southern China

In recent years, significant breakthroughs in gas exploration have been made in Neoproterozoic strata in the Yangtze Block, in southern China, as the Anyue super gas field was discovered in the central Sichuan region. The potential of Neoproterozoic exploration in other parts of the Yangtze Block remains a question. Defining the development and distribution rules of Neoproterozoic source and reservoir strata is an important reference for the next step of deep-zone oil and gas explorations in the Yangtze Block. Based on field surveys and sample collections, the analyses of many predecessor field sections and drilling logging data of the Neoproterozoic in the Yangtze Block, source-rock series tests and analyses, as well as analyses of reservoir thin sections, and the distribution rules of the source and reservoir strata were determined by industrial mapping methods. Three sets of source rocks are found in the Neoproterozoic in Yangtze Block, namely, the Datangpo Formation, Doushantuo Formation, and the third member of the Dengying Formation. From top to bottom, the thermal evolutions in the three sets of source rocks show an increasing trend, with the Dengying Formation reaching the stage of over-maturation, while that of Doushantuo and Datangpo formations enter thermal metamorphism stages. The source rocks of the Datangpo Formation are relatively limited in distribution, displaying a northeastward rift style, whereas those of the Doushantuo Formation are distributed widely with two thickness centers. The Neoproterozoic reservoirs in the Yangtze Block developed in the Dengying Formation, with the carbonate reservoir spaces mainly comprising caves, dissolved bores, or pores and cracks. The thickness center of the dolomite reservoirs in Dengying Formation are mainly located in the Middle and Upper Yangtze carbonate platform marginal zones, which are distributed in the eastern Sichuan Basin, and in the Mianyang–Changning rifting platform margin belts in the central Sichuan Basin and the northern Hubei areas. Based on the typical reservoir anatomy, the hydrocarbon accumulation rules of the Neoproterozoic in the Yangtze Block are summarized as “near the rift trough or the passive continental margin hydrocarbon generation centers, adjacent to Karst bioherm-beach reservoir, and stable structural zones afterwards”.

The Anyue Giant Gas Field in the Sichuan Basin as the Largest Gas Field in Marine Carbonate Deposits from Domestic China

Abstract —The Anyue gas field is located in the middle part of the Sichuan Basin, SW China. It occurs in the oldest marine carbonate strata and is characterized by the highest degree of thermal evolution and the largest gas reserves in China. A significant breakthrough was made with the Gaoshi-1 risk-taking exploration well deployed in 2011. As of 2015, the proven geologic reserves of natural gas were 657.4 billion m3, and the total gas reserves including proven reserves, controlled reserves, and predicted reserves exceeded 1.5 trillion m3. A total of three sets of gas-bearing strata are developed in the Anyue gas field in a descending sequence: The gas reservoir in the Cambrian Longwangmiao Formation (Є1l) is treated as a structure-lithologic gas reservoir; the gas reservoir in Section No. 4 of the Dengying Formation (Z2dn4) is a structure-stratigraphic gas reservoir; and the gas reservoir in Section No. 2 of the Dengying Formation (Z2dn2) is a structural gas reservoir. A comparative analysis of the gas sources has shown that the gas Cambrian of reservoirs was mainly from mudshale of the lower Cambrian Maidiping and Qiongzhusi formations and the gas of the Dengying Formation reservoirs was from mudshale of the Qiongzhusi Formation and mudstone of Section No. 3 of the Dengying Formation. All gas reservoirs are referred to as reservoirs of dry gas with medium or low contents of sulfur and medium contents of CO2. Gas reservoirs in Є1l are characterized by a large burial depth, a high temperature, and a high pressure, while the gas reservoirs in Z2dn2 and Z2dn4 are characterized by an ultralarge depth, a high temperature, and a normal pressure. The accumulation of gas reservoirs is controlled mainly by two factors. The distribution of hydrocarbon generation centers is controlled by the late Sinian–early Cambrian intracratonic rift, which acts as effective updip sealing conditions for gas reservoirs in the Dengying Formation. The late Sinian–early Cambrian Gaoshiti–Moxi paleouplift experienced a long-term inherited development, which controlled the generation and distribution of three sets of large-scale high-quality reservoirs in Z2dn4, Z2dn2, and the Longwangmiao Formation and the generation of three sets of high-quality reservoir–caprock assemblages. An inherited giant structural trap with a longterm stable development is always a favorable zone for petroleum accumulation.

A revised method for reconstructing the hydrocarbon generation and expulsion history and evaluating the hydrocarbon resource potential: Example from the first member of the Qingshankou Formation in the Northern Songliao Basin, Northeast China

Reconstructing the hydrocarbon generation and expulsion history of source rocks is an essential part of evaluating the hydrocarbon resource potential by genetic method. The hydrocarbon generation potential method is an efficient tool for quantifying the hydrocarbon generation and expulsion characteristics of source rock and evaluating the hydrocarbon resource potential based on Rock-Eval data. Although various revised versions of the method are publicly available, the following problems remain to be resolved: (a) the method is subjective; (b) implicit limitations are observed; and (c) rock mass loss is not considered, which may result in unacceptable errors. In this study, we propose a revised hydrocarbon generation potential method. Expressions for calculating the original rock mass (Go), original total organic carbon (TOCo), transformation ratio (TR), hydrocarbon expulsion ratio (ER) and hydrocarbon expulsion efficiency (f) were developed and incorporated into the hydrocarbon generation and expulsion history reconstruction and hydrocarbon resource potential evaluation, and these expressions combined conventional and unconventional resource evaluations systematically with objective and accurate results. The first member of the Qingshankou Formation (K2qn1) in the Northern Songliao Basin, Northeast China, was used as an example to demonstrate the application of the proposed method. The results have been compared with the unrevised method using the same Rock-Eval data sets and verified with previous reports to demonstrate its reliability. The results also indicate that the hydrocarbon generation threshold (HGT) and hydrocarbon expulsion threshold (HET) of K2qn1 are Ro = 0.4% and Ro = 0.6%, respectively. Three hydrocarbon generation and expulsion peak stages were identified: K2n (81–74 Ma), K2m (74–66 Ma), and N2t (66–0 Ma). The hydrocarbon generation and expulsion centers of K2qn1 are mainly the Qijia-Gulong Sag and Sanzhao Sag. The resource potentials of conventional oil, unconventional tight oil, and shale oil associated with K2qn1 source rocks in the Northern Songliao Basin are 8.15 × 108 t, 22.97 × 108 t, and 62.1 × 108 t, respectively.

Quality, hydrocarbon generation, and expulsion of the Eocene Enping Formation source rocks in the Wenchang Depression, western Pearl River Mouth Basin, South China Sea

Recently, increasing numbers of oil and gas reservoirs have been discovered in the Wenchang Depression, western Pearl River Mouth Basin, South China Sea, revealing prospects for hydrocarbon exploration. The Enping Formation (E3e) is a key target layer for the development of source rocks. However, previous work has only focused on lacustrine swamp source rocks of E3e in the Wenchang A Sag, without a systematic study of shallow lacustrine source rocks. In this study, the quality of E3e shallow lacustrine source rocks is reevaluated, and the hydrocarbon generation and expulsion characteristics are analyzed using relevant geological data and constructing a conceptual model. The results show that the E3e2 source rocks have greater thickness (50–600 m) and similar organic matter abundance (0.5–2.5%) compared with the E3e1 source rocks (50–500 m and 0.5–2.5%). On the whole, the E3e source rocks were deposited in the continental environment and are dominated by Type II and Type III kerogen. Meanwhile, the E3e source rocks of the Wenchang A Sag are in the stage of mature to over mature, while those of the Wenchang B Sag are in the stage of low mature. Vertically, the hydrocarbon generation potential of the E3e2 source rocks is greater than E3e1. Also, the cumulative hydrocarbon production of steep slope in the Wenchang A Sag is larger than that in the Wenchang B Sag. In addition, the corresponding vitrinite reflectances of hydrocarbon expulsion threshold and peak are 0.72 and 0.96%, respectively. Horizontally, four hydrocarbon generation and expulsion centers were mainly concentrated in different subsags of the Wenchang A and B Sags for E3e. The maximum values of hydrocarbon generation and expulsion intensity for E3e1 are 1500 × 104 t/km2 and 1000 × 104 t/km2, respectively, while those for E3e2 are 1800 × 104 t/km2 and 1200 × 104 t/km2, respectively, with the expulsion efficiency of 75%.

Distribution rules, main controlling factors and exploration directions of giant gas fields in the Sichuan Basin

Over the past decade, great progresses have been made in natural gas exploration in the Sichuan Basin, where several large gas fields (such as Anyue) have been discovered. With the increase of data and the deepening of exploration, new knowledges have been gained in geological theory, thus it is necessary to further analyze the distribution characteristics and main controlling factors of large gas fields, thus to put forward new exploration directions for large gas fields. Therefore, based on the statistics on the geological parameters of 20 large gas fields discovered in this basin, the distribution rules, formation conditions and main controlling factors of large gas fields were analyzed, and the follow-up exploration directions were proposed. The following results were achieved. (1) Large gas fields are developed in different tectonic regions in the Sichuan Basin, mostly in the low and gentle tectonic belts in the central Sichuan Basin. Large gas fields are developed in seven series of strata in longitudinal stratigraphic sequences, which are dominated by the reef-shoal large gas fields formed in the Upper Permian Changxing–Lower Triassic Feixianguan Fms. (2) There are four sets of source rocks contributing to the formation of large gas fields, mostly from the assemblage of Xujiahe Fm source rocks. (3) Reservoirs in the large gas fields are dominated by porous carbonates and tight sandstones; large gas fields are mostly structural–lithological ones and normal pressure ones. (4) The development of marine large gas fields are mainly controlled by intracratonic rifts and paleo-uplifts. The controlling effect of intracratonic rifts is mainly from three aspects, namely the hydrocarbon generation center of source rocks, high-energy facies belts on the platform edges, and lateral sealing for hydrocarbon accumulation. The controlling effect of the paleo-uplifts mainly acts from another three aspects: intra-platform high-energy facies belts, karstic dolomite reservoirs and long-term hydrocarbon accumulation. The structures of foreland basins controlled the development of the continental large gas fields from four aspects: tectonic setting, source and reservoir assemblage, trap type and fracture distribution. In conclusion, a total of 5 domains with 14 favorable zones are the follow-up exploration directions of large gas fields in the Sichuan Basin.

К ВОПРОСУ О ПРИРОДЕ И МЕХАНИЗМЕ ФОРМИРОВАНИЯ ЗАЛЕЖЕЙ УГЛЕВОДОРОДОВ НА ШЕЛЬФЕ ВЬЕТНАМА

The paper presents the results of the study of main factors determining conditions of formation and distribution of oil and gas deposits within the Cenozoic sedimentary cover and Precenozoic granite basement of the Vietnam shelf. The structural and tectonic model of the Kyulong basin constructed by the authors allows to reveal the conditions of formation of regional and local structures in the sedimentary cover containing hydrocarbon deposits; mechanisms of hydrocarbon traps emergence and hollow space (collectors); genesis of hydrocarbons, including the hydrocarbons existed in the basement rocks; the possible mechanism of migration and accumulation of hydrocarbons in the basement rocks. The traps which are real or potential reservoirs of hydrocarbons in the body of a crystal socle are widely developed. The structural and tectonic processes in the basement itself resulted in the development of positive morfostructures (domes, protrusions) the cores of which are made of disintegrated (granulated) rocks of a crystalline cap. In order to reconstruct the chronothermobaric conditions of occurrence and evolution of hydrocarbon generation centers and to restore the conditions of formation and distribution patterns of oil and gas accumulations on the shelf of Vietnam, three-dimensional modeling of generation and accumulation hydrocarbon systems was performed using the basin modeling technology and PetroMod software (Schlumberger, Ltd, USA). Studies of hydrocarbon biomarkers of oil fields in the Kyulong basin, including those located in the crystalline basement have shown the similarity of biomarker parameters of oil and organic matter, which demonstrates the organic nature of the oil fields of the basement on the shelf of Vietnam

Characteristics and controlling factors of tight sandstone gas reservoirs in the Upper Paleozoic strata of Linxing area in the Ordos Basin, China

Due to the large resource potential of tight sandstone gas, the Upper Paleozoic strata of the Linxing area has become an important exploration target in the Ordos Basin. In this study, by analyzing the distribution characteristics of tight sandstone gas (TSG), the relations of source-reservoir assemblages were divided into three types containing interbedded with source rocks (Type I), adjacent to source rocks (Type II) and far from source rocks (Type III). Five factors were identified to control their genesis, migration, and accumulation. Firstly, the gas generation intensity of source rocks is larger than 10 × 108 m3/km2, which indicated that source rocks could provide gas to the reservoirs. The gas generation centers of source rocks control the distribution of TSG reservoirs, while the areas among the hydrocarbon generation centers were the enrichment zones for TSG. Secondly, under the condition of generally tight reservoirs, the sandstone reservoir which has good quality (high porosity, high permeability) provided the favorable accumulation condition for TSG. Thirdly, the study area experienced one stage of gas charging mainly from the late early Jurassic to late early Cretaceous, which was 178 to 100Ma. Continuous gas generation and expulsion led to the sustained accumulation of TSG. Fourthly, with the general development of overpressure in the Upper Paleozoic strata, gas expansion force as the main power drive natural gas to migrate into the reservoirs of type I and type II during the accumulation period. Finally, the development of faults and fractures provided a migration path for natural gas charging in the reservoir of type III vertically. The existence of microcracks can improve the petrophysical properties of tight reservoirs. Under the joint control of these factors, the reservoir of Type I is the most favorable exploration target.

Characteristics of hydrocarbon transport systems and migration in slope areas of Qikou Sag, Bohai Bay Basin

The transport system plays an important role in hydrocarbon accumulation in slope area. The geochemical characteristics of the reservoir indicate that the oil and gas in this area generally have the tendency of migration and accumulation from the hydrocarbon generation center to the high part of slope. According to the relationship between source kitchens and traps, the hydrocarbon migration is divided into three types: inside source accumulation, near source vertical migration and outside source accumulation, controlled by the differential pressure between source rock and reservoir, dominant pathway-cap assembly and dominant migration phase respectively. The main types of migration pathway in the slope area are sand bodies, faults and unconformities, and the matching relationship between them controlled the direction and mode of oil and gas migration and accumulation in the slope area. The hydrocarbon migration and accumulation of middle-shallow layer in the low-middle slope are controlled by the dominant pathways and the matching relationship between faults and cap rocks, the hydrocarbon migration and accumulation in the middle slope are controlled by the favorable sedimentary facies, and the hydrocarbon migration and accumulation in the high slope are controlled by the distribution of sand bodies and favorable structures.

Control of magmatism on gas accumulation in Linxing area, Ordos Basin, NW China: Evidence from fluid inclusions

This paper takes the Linxing area of the eastern margin of Ordos Basin as an example. Based on the data of reservoir fluid inclusions (FI) and combined with the history of buried thermal history in Linxing area, the main effects of magmatism on the gas accumulation time, accumulation period, gas accumulation dynamics and accumulation pattern are studied. The vitrinite reflectance (Ro) in source rocks of Zijinshan tectonic area is higher than that in gentle tectonic area. The closer to Zijinshan pluton, the more it tends to single period natural gas charging, the earlier time of gas charging. The characteristics of natural gas accumulation are evidently regional and zonal. Gas accumulation in gentle tectonic area conforms to the law of “gas accumulation in near source reservoir is earlier than remote source reservoir”. The gas generated from the source rocks in the lower formation of the Zijinshan tectonic area reached the upper formation rapidly through the faults and fractures caused by the uplift of the Zijinshan pluton, and the accumulation interval time between the near source and remote source formation is relatively short. The Zijinshan tectonic area is the long-term high-pressure area and high-fluid potential area. The fluid potential in gentle tectonic area is low, and the fluid potential difference between the north and south is the motive force to promote the long distance lateral migration of gas. Zijinshan tectonic area is the hydrocarbon generation center and driving force source area, and gas accumulated rapidly from bottom to top. The features of gas accumulation in gentle tectonic area are dominated by vertical accumulation, supplemented by lateral supplementation. Since the Late Cretaceous, a large number of deep faults have been caused by the strong uplift of Zijinshan pluton, and a large number of natural gas are scattered through the faults and the reservoirs are destroyed. The faults in gentle tectonic area are not developed, and the natural gas preservation conditions are good, with good exploration prospects.

Distribution and exploration direction of medium- and large-sized marine carbonate gas fields in Sichuan Basin, SW China

Abstract Based on the analysis of the basic characteristics of medium- and large-sized marine gas fields in Sichuan Basin, combined with the division of major reservoir forming geological units in the marine craton stage and their control on key hydrocarbon accumulation factors, the distribution law of medium- and large-sized marine carbonate gas fields in the basin was examined and the exploration direction was pointed out. Through the analysis of the periodic stretching-uplifting background, it is concluded that five large scale paleo-rifts, three large scale paleo-uplifts, five large scale paleo erosion surfaces were formed in the marine craton stage of Sichuan Basin, and these geological units control the key reservoir forming factors of medium and large sized gas fields: (1) Large-scale paleo-rifts control the distribution of high-quality hydrocarbon generation centers. (2) The margin of large-scale paleo-rifts, high position of paleo-uplifts and paleo erosion surfaces control the distribution of high-quality reservoirs. (3) Large-scale paleo-rifts, paleo-uplifts, paleo erosion surfaces and present tectonic setting jointly control the formation of many types of large and medium-sized traps. (4) Natural gas accumulation is controlled by the inheritance evolution of traps in large geological units. Based on the comparative analysis of the distribution characteristics of medium- and large-sized gas fields and large geological units, it is proposed that the superimposition relationship between single or multiple geological units and the present structure controls the distribution of medium- and large-sized gas fields, and the “three paleo” superimposed area is the most advantageous. According to the above rules, the main exploration fields and directions of medium- and large-sized marine carbonate gas fields in Sichuan Basin include periphery of Deyang-Anyue paleo-rift, eastern margin of Longmenshan paleo-rift, margins of Kaijiang-Liangping oceanic trough and Chengkou-western Hubei oceanic trough, the high part of the subaqueous paleo-uplifts around Central Sichuan, paleo erosion surfaces of the top boundary of Maokou Formation in eastern and southern Sichuan Basin, paleo erosion surfaces of the top boundary of the Leikoupo Formation in central and western Sichuan Basin.