Reservoir Caprock Assemblages Research Articles

Exploration breakthrough and factors for enrichment and high-yield of hydrocarbons in ultra-deep clastic rocks in Linhe Depression, Hetao Basin, NW China

Based on drilling and logging data, as well as geological experiments, the geological characteristics and factors controlling high-yield and enrichment of hydrocarbons in ultra-deep clastic rocks in the Linhe Depression, Hetao Basin, are studied. The results are obtained in four aspects. First, the inland saline lacustrine high-quality source rocks developed in the Paleogene in the Linhe Depression have the characteristics of early maturity, early expulsion, high hydrocarbon yield, and continuous and efficient hydrocarbon generation, providing an important resource basis for the formation of ultra-high pressure and high-yield reservoirs. Second, the weak compaction, early charging, and weak cementation for pore-preserving, together with the ultra-high pressure for pore-preserving and fracture expansion to improve the permeability, leads to the development of high-quality reservoirs with medium porosity (greater than 15%) and medium permeability (up to 226×10−3 μm2) in the ultra-deep strata (deeper than 6 500 m), which represents a greatly expanded space for oil and gas exploration. Third, the Linhe Formation adjacent to the trough exhibits a low net-to-gross (NTG) and good reservoir-caprock assemblage, and it is overlaid by very thick high-quality mudstone caprock, which are conducive to the continuous and efficient hydrocarbon generation and pressurization and the formation of ultra-high pressure oil and gas reservoirs. Fourth, the most favorable targets for ultra-deep exploration are the zones adjacent to the hydrocarbon generating center of the Paleogene Linhe Formation and with good tectonic setting and structural traps, mainly including the Xinglong faulted structural zone and the Nalinhu faulted buried-hill zone. The significant breakthrough of ultra-deep oil and gas exploration in the Linhe Depression reveals the good potential of ultra-deep clastic rocks in this area, and provides valuable reference for oil and gas exploration of ultra-deep clastic rocks in other areas.

Decoding the complex fluvial-lacustrine sedimentary interactions: Insights from the Neogene Guantao Formation in the Bohai Bay Basin and Modern Poyang Lake, China

Small-scale lake level variations lead to significant landward/basinward shifts in the depositional system, thereby facilitating the widespread development of fluvial-lacustrine interaction sedimentary systems. Such systems are commonly found in low-gradient shallow-water continental down-warped lacustrine basins, which are favorable for the formation of composite reservoir-caprock assemblages. Nevertheless, our understanding of the sedimentary stratigraphy of the Neogene Guantao Formation remains limited due to the complex and variable spatial and temporal associations between fluvial and lacustrine deposits. Integrated analysis of the geomorphology and stratigraphy of the modern Poyang Lake Basin and ancient Bohai Bay Basin (BBB) allows us to develop a process-based fluvial-lacustrine interaction model of shallow-water depositional system. Three physiographic zones are identified based on seasonal lake shoreline migration during a certain geological sequence unit, namely fluvial-dominated zone (FDZ), fluvial-lacustrine interaction zone (FLIZ) and lacustrine-dominated zone (LDZ), respectively. The FDZ is always above the maximum lake shoreline without affection by lake basin water body and is characterized by channelized dendritic pattern of distributary channels with positive rhythmic cycles. The FLIZ is a dynamic interaction region between the maximum lake shoreline and the lowest lake shoreline. Reticular distributary channels, delta front and prodelta/lake deposits vertically superimpose and dominate the system that is featured by complex sandbody, stacked positive and negative rhythms and strong water body segmentation. The LDZ, away from the fluvial effect, was identified below the lowest lake shoreline exhibiting polycentric sheet water body, dominated by lacustrine mudstone interspersed with thin sheet-like sandstone. These results shed light on the spatial and temporal sedimentary heterogeneity in such dynamic fluvial-lacustrine interaction systems. The proposed fluvial-lacustrine interaction model may serve as a valuable analogue for identifying sedimentary types and predicting sandstone reservoirs in similar shallow-water settings ranging from continental down-warped lacustrine basins to cratonic basins, and fault-depression basin gentle-slope belts.

Properties and Model of a Lacustrine Shale Oil Reservoir: A Case Study of the Upper Fourth Member and Lower Third Member of the Shahejie Formation in Dongying Sag and Zhanhua Sag, Jiyang Depression

By combining thermal simulation experiments with core data, thin sections, scanning electron microscopy (SEM), source rock, and high-pressure mercury and gas adsorption analysis, this paper evaluates the properties and models of shale reservoirs in the upper fourth member and the lower third member of the Shahejie Formation in Dongying Sag and Zhanhua Sag. The results show that the oil shale is a high-quality source rock with petroleum generation potential. Inorganic mineral pores, organic pores, and fractures have developed with petroleum storage capacity. Clay and organic-rich soft shale lithofacies are interbedded with carbonate-rich hard shale lithofacies to form sandwich-type source–reservoir–caprock assemblages with internal sealing properties. Bitumen occurs mostly in the free state, and to a lesser extent is adsorbed, and shows flow characteristics. The migration resistance of the bitumen is displacement pressure, including capillary force and adsorption resistance, and the main force is pore fluid pressure. The migration modes of the bitumen include both subcritical flow and instantaneous flow, which are controlled by pore fluid pressure, displacement pressure, and the rock’s fracture strength. Owing to the multi-scale characteristics of the shale reservoir space, a vein-type model of a multi-scale progressive transport network is developed that obeys Murray’s law with a dominant migration pathway in the shale reservoir. The shale oil reservoir is a special lithologic reservoir controlled by the sedimentary environment and has self-generation, self-storage, and self-sealing characteristics with developed pore fluid overpressure and a multi-scale transport network.

Controlling effects of cap rocks on the formation of deep geothermal resources

Cap rocks with high thermal insulation are important for deep geothermal systems at a depth of 3000‒6000 m. Based on the deep geothermal geological conditions in the Fujian-Guangdong-Hainan area of South China, this study established an ideal geological model of reservoir-cap rock assemblages and simulated the geothermal field distribution of cap rocks of different thicknesses and thermal conductivity. The simulation results show that the vertical geothermal temperature distribution in an uplifted area of a depression was present as inverted mirror reflections relative to the elevated area of the basement. Specifically, the isotherms above the elevated area are convex in shape, while those below the elevated area are concave. There is a temperature equilibrium line between the convex and concave isotherms. The heat flow moves from the depressed area to the uplifted area below the temperature equilibrium line and migrates in an opposite direction above the line. On this base, this study conducted the inversion of geothermal temperature fields in typical areas with thin, moderately thick, and thick cap rocks. The results indicate that, at the depth of 3000–6000 m, areas with thin cap rocks (igneous rock zone in the coastal area of Fujian) mainly host moderate- to low-temperature hydrothermal resources; areas with moderately thick cap rocks (Yuezhong Depression) have the geothermal temperature ranging between 100 °C and 200 °C and may develop moderate- to high-temperature hydrothermal resources and hot dry rocks (HDRs), with the former superimposing on the latter; and areas with thick cap rocks (onshore Beibuwan Basin) have a geothermal temperature of 120‒220 °C, and contains mainly moderate- to high-temperature hydrothermal resources and HDRs. Therefore, it is recommended that the evaluation, exploitation, and utilization of deep geothermal resources be carried out according to the burial depth of the temperature equilibrium line and the specific demand for geothermal resources.

Carbon Dioxide Storage Potential of Cenozoic Saline Aquifers in the South Yellow Sea Basin

Carbon dioxide (CO2) storage in underwater reservoirs is a valuable method of reducing carbon emissions. Saline aquifers such as those in the South Yellow Sea Basin (SYSB), China, have great potential for geological CO2 storage. Thus, we use the recommended calculation method of USDOE and a formation volume model to determine the geological conditions for CO2 storage and estimate the CO2 storage capacity of the Cenozoic saline aquifers in the SYSB (depth: 800–3200 m). Overall, the SYSB exhibits weak fault activity and seismicity, medium and low geothermal fields, four types of source sandstone reservoir, and four sets of carbon reservoir–caprock assemblages developed from the Cenozoic strata, providing relatively good geological conditions for CO2 storage. The estimated capacity of the Cenozoic strata ranges from 39.59 Gt to 426.94 Gt (average: 155.25 Gt), indicating an extensive storage capacity that can meet the carbon sequestration needs of Shandong and Jiangsu Provinces for approximately 89 years. The Yantai Depression has a lower geothermal gradient and terrestrial heat, weaker seismic activity, and double the storage capacity of the Qingdao Depression, indicating that it is the most suitable area for Cenozoic CO2 storage in the SYSB, whereas the Laoshan Uplift is not suitable for storage. This study provides a scientific basis for the selection of offshore CO2 storage sites.

Mechanisms of deep oil–gas accumulation: New insights from the Carboniferous Central Depression, Junggar Basin, China

To investigate the mechanisms of deep oil–gas accumulation in superimposed basins in western China, and identify deep oil–gas reserves in the Junggar Basin, this study examined Carboniferous reservoirs in the Central Depression of the basin. We determined the hydrocarbon physical properties and geochemical characteristics, and controlling factors on hydrocarbon accumulation in the deep part of the Central Depression. We present a geological model of oil–gas accumulation based on analog modeling of reservoir formation. The deep hydrocarbons in the study area are mainly light–medium oil and wet natural gas, which were mainly derived from Permian and Carboniferous source rocks. The hydrocarbon source rocks and their thermal evolution led to hydrocarbon accumulation in the study area. Adjacent source–reservoir rocks on both sides of faults were key to vertical hydrocarbon migration and multi-stage charging. Suitable reservoir–cap rock assemblages were also important for reservoir preservation. The hydrocarbon accumulation model involves a source–reservoir link along faults, late charging, and paleo-uplifts. The reservoir types include those linked to source rocks by large-scale faults and those in paleo-uplifts surrounded by oil-generating depressions, which both have good exploration prospects. This accumulation model may be applicable to deep parts of other superimposed basins.

Organic geochemical characteristics and gas prospectivity of Permian source rocks in western margin of Songliao Basin, northeastern China

The Permian in western margin of Songliao Basin is a strategic potential field of oil and gas resources in northeastern China, but the systematic researches since few boreholes were drilled up to Permian strata, as well as there is a lack of seismic and well-logging data. This paper presents the lithological composition of the Permian Formations on the basis of regional geological survey in western margin of Songliao Basin. A total of 60 mudstones and shales were collected to evaluate the organic geochemical and petrophysical characteristics and gas prospectivity of Permian source rocks. The Permian is composed of Shoushangou, Dashizai, Zhesi and Linxi Formation, which represent large sets of mudstones and shales, which are mainly deposited in a weakly to strongly reducing marine environment. The primary organic matter precursors in Permian were lower aquatic organisms such as zooplankton and algae, while a few samples of Linxi Formation indicate mixed sources of lower aquatic organisms and terrigenous higher plants. The Permian gas–prone source rocks are at over–mature stage with vitrinite reflectance Ro% = 2.01%–3.14% and mainly classified as fair to good quality and type II–III kerogens, and generally have a tricyclic terpane distribution pattern of C21>C23>C20, but Shoushangou Formation and Linxi Formation have subordinate patterns of C21>C20>C23 and C23>C21>C20, respectively. The residual organic matters in Permian source rocks have CH4 yields up to 24.34 mg/g∙TOC at EASY%Ro = 4.45%, which indicate the possibility of secondary gas generation at Ro% = 2.0%–3.5%. The pores and fractures are developed in Permian source rocks with widths of 5.28–18.64 μm, and mean values of porosity and permeability are 2.17% and 0.0043 × 10−3 μm2, respectively. The source–reservoir–cap rock assemblages in Carboniferous–Permian and Mesozoic sedimentary sequences are included in situ and near–source accumulation in Permian, and long–distance migration and accumulation in underlying Carboniferous and overlying Triassic, Jurassic and Cretaceous. The Permian system can be regarded as a potential gas exploration target in the western margin of Songliao Basin.

Using characteristics of pressure-temperature induced permeability variation of typical carbonate rock to determine its performance as reservoir or cap rock

The current research on carbonate rock often focuses on the storage space for oil and gas, and exploration of carbonate rock in petroliferous basins also mainly searches for high-quality reservoir rock for hydrocarbons. However, the importance of effective carbonate reservoir-cap rock configuration is increasingly highlighted, as hydrocarbon exploration advances towards deeper and older strata. Exploration practice shows that the favorable facies belt of carbonate rock, though deeply buried, still develops highly desirable reservoir rock with high porosity and permeability. Therefore, the presence of an effective carbonate cap rock collaborating with this reservoir rock becomes key to hydrocarbon exploration in deep carbonate rock. This research, for the first time, systematically and thoroughly carries out permeability measurement through the whole triaxial compression process of typical carbonate rock at varied temperatures, and captures the permeability evolution during deformation and failure, affected by temperatures and confining pressures. Test results show that typical dolomite and limestone present varied permeability variation characteristics in a triaxial loading state. Dolomite appears to be more of reservoir rock. It presents higher critical confining pressure for brittle–ductile transition, and is more prone to fracturing. Its permeability grows with temperature elevation. As for limestone, it has better performance as cap rock, which is embodied as the lower critical confining pressure for brittle–ductile transition, high sealing capacity, and permeability reduction with elevated temperatures. To sum up, vertical stacking of dolomite and limestone can form an effective reservoir-cap rock assemblage for hydrocarbon accumulation.

Exploration status of the deep Sinian strata in the Sichuan Basin: Formation conditions of old giant carbonate oil/gas fields

To construct a giant Sichuan gas province, it is in an urgent need of exploring new replacement areas with abundant natural gas resources and great exploration potential. In this paper, the formation conditions (e.g. source rock, reservoir and play) and the distribution laws of the deep-seated old giant marine carbonate oil/gas fields in China's Craton Basins were investigated systematically. Then, the accumulation and enrichment conditions of deep Sinian natural gas in the Sichuan Basin were analyzed. Finally, potential and favorable target zones of natural gas exploration in the Dengying Formation of Upper Sinian were evaluated. And the following research results were obtained. Firstly, the effectiveness and scale of source kitchens, reservoirs and reservoir–caprock assemblages and the proximity are the necessary conditions for the formation of deep-seated giant carbonate oil/gas fields, and paleo-uplifts, paleo-slopes and paleo-fault zones are the favorable areas of searching deep-seated giant carbonate oil/gas fields. Secondly, in the Sichuan Basin, three sets of high-quality source rocks are developed in the Neoproterozoic–Cambrian System, and their maturity of organic matter is still in the optimal window for cracking gas, so the gas generation scale is large. Thirdly, after the microbial carbonate rocks of Dengying Formation in the Sichuan Basin were reconstructed by constructive diagenesis, effective reservoirs are formed and distributed widely. Fourthly, owing to the integrated source rocks and cap rocks of Dengying Formation, the marginal platform and the intra platform have favorable conditions for proximal hydrocarbon accumulation. In conclusion, the deep Sinian in the Sichuan Basin has good conditions of hydrocarbon accumulation and it is an important replacement area of natural gas exploration. Paleo-uplifts and slopes in the central Sichuan Basin have been the favorable locations of natural gas accumulation for a long period. Large-scale exploration shall focus on four favorable areas, including the marginal platform zone in the fourth member of Dengying Formation, the marginal platform zone in the second member of Dengying Formation, the bioherm shoalbody of Dengying Formation intra platform in the paleo-uplifts and slopes of the central Sichuan Basin, and the bioherm shoalbody of Dengying Formation in the eastern Sichuan Basin.

Formation mechanisms of deep and ultra-deep over pressure caprocks and their relationships with super-large gas fields in the petroliferous basins of China

Super-large natural gas fields have been discovered in the deep and ultra-deep layers of onshore and offshore petroliferous basins in China since the beginning of the 21st century, and the geological conditions for the formation of these gas fields and their development laws have already been discussed in a large number of literatures, but the relationship between over pressure and the formation of this kind of gas fields is still less researched. In this regard, this paper firstly analyzed the gas reservoir development law, sealing conditions and over pressure characteristics of deep and ultra-deep super-large gas fields. Then, the formation mechanisms of deep and ultra-deep over pressure caprocks were investigated and the development law of deep and ultra-deep super-large gas fields and their relationship with over pressure caprocks were discussed. Finally, the favorable areas for the next exploration of deep and ultra-deep natural gas were pointed out. And the following research results were obtained. First, the formation of deep and ultra-deep super-large gas fields is closely related to the development of over pressure caprocks. Over pressure caprock is a necessary condition for the formation of deep and ultra-deep super-large gas fields, and there are three over pressure formation mechanisms, including pressure seal of salt-gypsum layer, pressure seal of residual uplift and pressure seal of hydrocarbon-generating pressurization. Second, as for deep and ultra-deep over pressure caprocks and super-large gas fields, there are four reservoir–caprock assemblage modes under different pressure environments, i.e., over pressure salt-gypsum seal and over pressure super-large gas field (Type I), internal over pressure compartment and over pressure super-large gas field (Type II), high-pressure argillaceous shale seal at the bottom of over pressure compartment and normal-pressure super-larger gas field (Type III), and over pressure source rock seal and normal-pressure super-larger gas field (Type IV). In conclusion, there are Type I super-large gas fields in the Kuqa Depression of the Tarim Basin, types II and III in the Junggar Basin, types I–IV in the Sichuan Basin and Type IV in the Bohai Bay Basin.

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.

Study on the characteristics of gas-generating reservoir-caprock assemblages and gas traps in coal measures in Fuxin Basin

As an unconventional natural gas reservoir, sand body gas has unique characteristics. The paper takes Fuxin Basin as the research object and carries out systematic research on the characteristics of sand gas generation reservoir cap combination. The main controlling factors are analyzed for the trap characteristics of the sand gas reservoir in the main formation. The results show that there are two types of gas source rocks in Fuxin Basin, namely, dispersed organic matter and concentrated organic matter reservoirs, which are mainly composed of two sets of strata. The first set is the lower channel sand bodies of the Fuxin Formation, and the second set is the third member of Shahejie Formation, The second alluvial fan-fan delta sand body. The caprock of Fuxin Formation is mudstone and siltstone in the middle and upper part of this group. The cover layer of Shahai Formation is mudstone and siltstone in the fourth member of Shahe Formation, with dense and uniform development in the whole area and stable sedimentation. Sand gas traps in Fuxin Basin are mainly controlled by two types of traps: structural traps and lithologic traps.

Hydrocarbon accumulation patterns of salt crust covered biogenic gas reservoirs in the Sanhu Depression, Qaidam Basin

Quaternary biogenic gas reservoirs are extensively developed in the Sanhu Depression of the Qaidam Basin, where the largest domestic biogenic gas production base has been built up. In recent years, however, the exploration of biogenic gas there encounters a variety of difficulties, such as the identification of true and false seismic abnormality, the determination of micro-relief structure and the identification and description of lithologic traps, which are the bottlenecks restricting its exploration breakthrough. In this paper, hydrocarbon accumulation patterns of biogenic gas were studied. Then, based on fine structure interpretation results, combined with laboratory experiments, the sealing capacity, distribution range, formation time and genesis of salt crust were discussed, and the salt crust covered hydrocarbon accumulation pattern of biogenic gas was put forward. Finally, combined with the conditions of source rocks and reservoirs, the exploration prospect of salt crust covered biogenic gas reservoirs was predicted. And the following research results were obtained. First, the Quaternary in the Sanhu Depression is composed of sandstone–mudstone interbeds of shore-shallow lake facies, with superior conditions of source rocks and reservoirs. Many source–reservoir–caprock assemblages are vertically formed. The biogenic gas has the characteristics of dynamic hydrocarbon accumulation, i.e., continuous migration, accumulation, diffusion and re-accumulation. Second, under the effect of Himalayan movement, the climate changes frequently and the salinity of the ancient lake is zoned in the Sanhu Depression. A freshwater area is formed at the inlet of the river in the south and a brine area is formed in the north. Under the influence of evaporation, the phreatic water in the north is salinized continuously, and a set of extensively distributed salt crust with steady thickness and a strong sealing capacity is formed at the eastern part of Lingjian fault. Third, the biogenic gas generated by dark mudstone of lacustrine facies in the depression center migrates laterally and vertically to Lingjian fault zone and gets accumulated under the sealing of salt crust. In conclusion, high-quality source rocks and reservoirs and the salt crust with a strong sealing capacity in the Sanhu Depression constitute a good spatial–temporal configuration relationship of source rocks, reservoirs and cap rocks, so salt crust covered biogenic gas reservoirs can be formed to provide abundant natural gas resources with a broad exploration prospect.

Hydrocarbon accumulation of composite-buried hill reservoirs in the western subsag of Bozhong sag, Bohai Bay Basin

There are abundant hydrocarbon resources in the western subsag of Bozhong sag in the Bohai Bay Basin, where oil–gas discoveries have been made in those shallow Neogene and Paleogene reservoirs and deep Mesozoic buried hill reservoirs, but no better understandings have yet been achieved in terms of the process of hydrocarbon accumulation and the relationship between deep buried hill reservoirs and the allocation of shallow reservoirs. Based on the organic geochemical analysis of source rocks and basin modeling of hydrocarbon generation evolution, distribution characteristics of fluid inclusion and homogeneous temperature measurement, combined with the characteristics of oil-source biomarkers, the process of hydrocarbon accumulation in this study area was resumed based upon the regional tectonic background. The following findings were obtained. (1) There are 3 sets of source rocks in the third and first members of Paleogene Shahejie Fm, and the second lower member of Paleogene Dongying Fm; the reservoirs in the peripheral uplift zones include Mesozoic volcanic rocks, Archean metamorphic rocks, and Paleogene–Neogene delta–fluvial porous sandstones. Hydrocarbon generated in this sag migrated along the fault and the unconformity surface to the slope before accumulated in the peripheral tectonic zones, resulting in 3 sets of source–reservoir–caprock assemblages formed with the characteristics of reservoir formation in compound oil and gas accumulation zones. (2) The stratum in the third member of Shahejie Fm is the main source rock. (3) The above three assemblages went through four periods of generating process during the geological time of 11–1 Ma. Vertically hydrocarbon sources first filled in the deep Mesozoic and Archean reservoirs, then migrated and accumulated in the shallow Neogene and Paleogene reservoirs, where multiple shore-term rapid filling of high-temperature fluids led to this typical oil and gas pooling mode.

Dolomite genesis and reservoir-cap rock assemblage in carbonate-evaporite paragenesis system

Regarding to the problem on the reservoir-cap rock assemblage evaluation in the carbonate-evaporite paragenesis system, this study examined the dolomite and reservoirs genesis and the characteristics of reservoir-cap rock assemblage. Based on the literature research of the global carbonate reservoirs and the case study on four profiles of carbonate-evaporite succession, together with geological and experimental work, three aspects of understandings are achieved. (1) Lithology of carbonate-evaporite paragenesis system is mainly composed of microbial limestone/bioclastic limestone, microbial dolomite, gypsum dolomite and gypsum salt rock deposited sequentially under the climatic conditions from humid to arid, and vice versa, and an abrupt climate change event would lead to the lack of one or more rock types. (2) There developed two kinds of dolomite (precipitation and metasomatism) and three kinds of reservoirs in the carbonate-evaporite system; and the carbon dioxide and organic acid generated during early microorganism degradation and late microbial dolomite pyrolysis process, and early dolomitization are the main factors affecting the development of microbial dolomite reservoirs with good quality. (3) In theory, there are 14 types of reservoir-cap rock assemblages of six categories in the carbonate-evaporite system, but oil and gas discoveries are mainly in four types of reservoir-cap rock assemblages, namely “microbial limestone/bioclastic limestone – microbial dolomite – gypsum dolomite – gypsum salt rock”, “microbial limestone/bioclastic limestone – gypsum salt rock”, “microbial dolomite – gypsum dolomite – gypsum salt rock” and “gypsum dolomite – microbial dolomite – tight carbonate or clastic rock”. These four kinds of reservoir-cap rock assemblages should be related with the climate change rules in the geologic history, and have good exploration prospects.

Hydrocarbon accumulation conditions and key exploration and development technologies for PL 19–3 oilfield

The PL 19–3 Oilfield is the only super-large monolithic oilfield with oil and gas reserves up to 1 × 109 t in the Bohai Bay Basin, and it has been successfully developed. Exploration and development practices have provided abundant data for analyzing formation conditions of this super-large oilfield. On the basis of the exploration and development history, fundamental reservoir features, and with available geological, geophysical and test data, the hydrocarbon accumulation conditions and key exploration & development technologies of the PL 19–3 Oilfield were discussed. The key conditions for forming the super-large Neogene oilfield include four aspects. Firstly, the oilfield is located at the high position of the uplift that contacts the brachy-axis of the multi-ridge slope in the biggest hydrocarbon-rich sag in the Bohai Bay Basin, thus it has sufficient hydrocarbon source and extremely superior hydrocarbon migration condition. Secondly, the large-scale torsional anticlines which formed in the Neogene under the control of the Tanlu strike-slipping movement provide sufficient storage spaces for oil and gas preservation. Thirdly, the “multiple sets of composite reservoir-caprock assemblages” developing in the special shallow-water delta further contributes greatly to the effective storage space for oil and gas preservation. Fourthly, due to the coupling of the uplift and strike slip in the neotectonic period, extensive faulting activities constantly released the pressure while the late period massive hydrocarbon expulsion of the Bozhong took place at the same time, which assures the constant and intense charging of oil and gas. The super-large PL 19–3 Oilfield was controlled by the coupling effects of all those special geologic factors. In view of this oilfield's features (e.g. violently reformation caused by strike slip, and the special sedimentary environment of shallow-water delta), some key practical technologies for exploration and development have been developed. Such technologies include: the special prestack depth migration processing for gas cloud zones, the prediction of thin interbed reservoirs based on high-precision inversion of geologic model, the reservoir description for the shallow-water braided river delta, the quantitative description for remaining oil in the commingled oil reservoirs with wide well spacing and long well interval, and the well pattern adjustment for formations during high water cut period in the complex fluvial-facies oilfields.

Quantitative analysis of reservoir-cap rock assemblages of the first member of Sanduo Formation and prediction of favorable regions in Gaoyou Sag, North Jiangsu Basin

Quantitative analysis of reservoir-cap rock assemblages of the first member of Sanduo Formation and prediction of favorable regions in Gaoyou Sag, North Jiangsu Basin

Accumulation characteristics and exploration strategies of coal measure gas in China

Coal measure gas is broadly defined as all natural gas occurring in coal measure strata while narrowly defined as the coalbed methane (CBM) in coal beds and the natural gas in the adjacent tight sandstone reservoirs. In this paper, the accumulation characteristics and control factors of narrowly defined coal measure gas in China were analyzed from the aspects of source rock distribution, coal–sandstone combination type, sedimentary facies and closed system to improve CBM development benefit. And the following research results were obtained. First, there are various coal–sandstone combination relationships in coal measure strata of coal bearing basins in China. Second, the widely-distributed source rocks provide sufficient gas sources for the enrichment of coal measure gas. Third, sedimentary facies dominate the combination relationships of source–reservoir–caprock assemblages of coal measure gas, so the inborn material base of coal measure gas accumulation is formed. The sedimentary systems of fluvial facies and delta facies are the most favorable sedimentary facies for the paragenesis and accumulation of coal measure gas for their coal beds and sandstones are developed. Fourth, the closed system controls the whole process of generation, enrichment and accumulation of CBM (coal measure gas). Three types of coal measure gas reservoirs are identified: self-source and self-reservoir CBM reservoirs, paragenetic CBM–sandstone gas reservoirs, coal-derived sandstone gas reservoirs, among which the first type is currently the main target of CBM exploration and development. Finally, the next exploration direction of coal measure gas was pointed out as follows. First, the exploration and evaluation of coal measure gas shall be focused on the giant basins with abundant coal measure gas, such as Qinshui, Ordos, Junggar, Hailar and Jixi. Second, coal measure gas reservoirs shall be explored specifically based on different types. It is necessary to carry out CBM exploration in the self-source and self-reservoir CBM enriched zones in the shallow layers, integrated exploration of CBM and sandstone gas in the paragenetic CBM–sandstone gas reservoirs in the deep layers, and sandstone gas exploration in coal-derived sandstone gas reservoirs.

Discussion on “sandwich” structures and preservation conditions of shale gas in the South Yellow Sea Basin

ABSTRACT In order to make a breakthrough in Mesozoic-Paleozoic shale gas exploration in the South Yellow Sea Basin, a comparison of the preservation conditions was made within the Barnett shale gas reservoirs in the Fortworth Basin, the Jiaoshiba shale gas reservoirs in Sichuan Basin and potential shale gas reservoirs in Guizhou Province. The results show that the “Sandwich” structure is of great importance for shale gas accumulation. Therein to, the “Sandwich” structure is a kind of special reservoir-cap rock assemblage which consist of limestone or dolomite on the top, mudstone or shale layer in the middle and limestone or dolomite at the bottom. In consideration of the Mesozoic-Paleozoic in the Lower Yangtze, and Laoshan Uplift with weak Paleozoic deformation and thrust fault sealing on both flanks of the Laoshan Uplift, a conclusion can be drawn that the preservation conditions of shale gas probably developed “Sandwich” structures in the Lower Cambrian and Permian, which are key layers for the breakthrough of shale gas in the South Yellow Sea. Moreover, the preferred targets for shale gas drilling probably locate at both flanks of the Laoshan Uplift.

Hydrocarbon preservation conditions in Mesozoic–Paleozoic marine strata in the South Yellow Sea Basin

In the South Yellow Sea Basin, Mesozoic–Paleozoic marine strata are generally well developed with large thickness, and they are characterized by multi-source and multi-stage hydrocarbon accumulation, providing a material basis for the formation of large-scale oil and gas fields. However, no substantial breakthrough has been made in this area. Based on previous research results, the complex tectonic pattern of this superimposed basin was formed by multi-stage tectonic movements and the favorable static conditions for hydrocarbon preservation were reworked or destroyed by later superimposition. Therefore, hydrocarbon preservation conditions are the key factors for restricting the breakthrough of marine oil and gas exploration in this area. In this paper, hydrocarbon preservation conditions of marine strata in the South Yellow Sea Basin were comprehensively analyzed from many aspects, such as tectonic movement, source conditions, caprock characteristics, magmatic activities, and hydrogeological and hydrogeochemical characteristics. It is indicated that the complex tectonic pattern of the South Yellow Sea Basin is resulted from tectonic events in multiple stages, and the development and evolution of regional source rocks are mainly controlled by two stages (i.e., the stable evolution stage of Mesozoic–Paleozoic marine basin and the Mesozoic–Cenozoic tectonic pattern transformation and basin formation stage), so the characteristics of differential oil and gas preservation are presented. Besides, better marine hydrocarbon preservation preconditions in this area are weaker tectonic reworking, development of high-quality thick source rocks, good vertical sealing capacity of caprocks, weaker magmatic activity and confined hydrogeological conditions. It is concluded that the Laoshan Uplift in the central part of the South Yellow Sea Basin is structurally stable with weaker faulting and magmatic activities, so it is better in oil and gas preservation conditions. Besides, several large-scale structural traps with good petroleum geological conditions and complete source–reservoir–caprock assemblages are developed in this area. Therefore, this area is the most promising region for Paleozoic marine oil and gas exploration in this basin.