Geochemical prerequisites for the formation of oil and gas accumulation zones in the South Turgay basin,Kazakhstan

This study predicts favorable oil and gas source-rock formation conditions in the Aryskum Depression of the South Turgay Basin,Kazakhstan.This study assesses the thermal maturity and characteristics of organic matter by determining its environmental conditions using data from geochemical analysis of core(pyrolysis)and oil(biomarkers and carbon isotopic compositions)samples.According to the geochemical parameters obtained by pyrolysis,the oil generation potential of the original rocks of most studied samples varies from poor to rich.The facies–genetic organic matter is predominantly humic and less frequently humus–sapropel,indicating organic matter accumulation in the studied samples were under moderately reducing conditions(kerogenⅢand Ⅱ types)and coastal–marine environments(kerogen typeⅠ).The carbon isotopic compositions of oils derived from the Jurassic deposits of the Aryskum Depression also indicate the sapropelic and mixed humic–sapropelic type of organic matter(kerogenⅡandⅠ).Biomarker analysis of oils indicates original organic matter formation in an anoxic environment.

Petroleum geological characteristics and exploration targets of the oil-rich sags in the Central and West African Rift System

Based on seismic,drilling,and source rock analysis data,the petroleum geological characteristics and future exploration direction of the oil-rich sags in the Central and West African Rift System(CWARS)are discussed.The study shows that the Central African Rift System mainly develops high-quality lacustrine source rocks in the Lower Cretaceous,and the West African Rift System mainly develops high-quality terrigenous organic matter-rich marine source rocks in the Upper Cretaceous,and the two types of source rocks provide a material basis for the enrichment of oil and gas in the CWARS.Multiple sets of reservoir rocks including fractured basement and three sets of regional cap rocks in the Lower Cretaceous,the Upper Cretaceous,and the Paleogene are developed in the CWARS.Since the Late Mesozoic,due to the geodynamic factors including the dextral strike-slip movement of the Central African Shear Zone,the basins in different directions of the CWARS differ in terms of rifting stages,intervals of regional cap rocks,trap types and accumulation models.The NE-SW trending basins have mainly preserved one stage of rifting in the Early Cretaceous,with regional cap rocks developed in the Lower Cretaceous strata,forming traps of reverse anticlines,flower-shaped structures and basement buried hill,and two types of hydrocarbon accumulation models of"source and reservoir in the same formation,and accumulation inside source rocks"and"up-source and down-reservoir,and accumulation below source rocks".The NW–SE basins are characterized by multiple rifting stages superimposition,with the development of regional cap rocks in the Upper Cretaceous and Paleogene,forming traps of draping anticlines,faulted anticlines,antithetic fault blocks and the accumulation model of"down-source and up-reservoir,and accumulation above source rocks".The combination of reservoir and cap rocks inside source rocks of basins with multiple superimposed rifting stages,as well as the lithologic reservoirs and the shale oil inside source rocks of strong inversion basins are important fields for future exploration in basins of the CWARS.

Research on thermal insulation materials properties under HTHP conditions for deep oil and gas reservoir rock ITP-Coring

Deep oil and gas reservoirs are under high-temperature conditions,but traditional coring methods do not consider temperature-preserved measures and ignore the influence of temperature on rock porosity and permeability,resulting in distorted resource assessments.The development of in situ temperaturepreserved coring(ITP-Coring)technology for deep reservoir rock is urgent,and thermal insulation materials are key.Therefore,hollow glass microsphere/epoxy resin thermal insulation materials(HGM/EP materials)were proposed as thermal insulation materials.The materials properties under coupled hightemperature and high-pressure(HTHP)conditions were tested.The results indicated that high pressures led to HGM destruction and that the materials water absorption significantly increased;additionally,increasing temperature accelerated the process.High temperatures directly caused the thermal conductivity of the materials to increase;additionally,the thermal conduction and convection of water caused by high pressures led to an exponential increase in the thermal conductivity.High temperatures weakened the matrix,and high pressures destroyed the HGM,which resulted in a decrease in the tensile mechanical properties of the materials.The materials entered the high elastic state at 150℃,and the mechanical properties were weakened more obviously,while the pressure led to a significant effect when the water absorption was above 10%.Meanwhile,the tensile strength/strain were 13.62 MPa/1.3%and 6.09 MPa/0.86%at 100℃ and 100 MPa,respectively,which meet the application requirements of the self-designed coring device.Finally,K46-f40 and K46-f50 HGM/EP materials were proven to be suitable for ITP-Coring under coupled conditions below 100℃ and 100 MPa.To further improve the materials properties,the interface layer and EP matrix should be optimized.The results can provide references for the optimization and engineering application of materials and thus technical support for deep oil and gas resource development.

Evaluation of source rocks and prediction of oil and gas resources distribution in Baiyun Sag,Pearl River Mouth Basin,China

By conducting organic geochemical analysis of the samples taken from the drilled wells in Baiyun Sag of Pearl River Mouth Basin,China,the development characteristics of hydrocarbon source rocks in the sag are clarified.Reconstruct the current geothermal field of the sag and restore the tectonic-thermal evolution process to predict the type,scale,and distribution of resources in Baiyun Sag through thermal pressure simulation experiments and numerical simulation.The Baiyun Sag is characterized by the development of Paleogene shallow lacustrine source rocks,which are deposited in a slightly oxidizing environment.The source rocks are mainly composed of terrestrial higher plants,with algae making a certain contribution,and are oil and gas source rocks.Current geothermal field of the sag was reconstructed,in which the range of geothermal gradients is(3.5–5.2)℃/100 m,showing an overall increasing trend from northwest to southeast,with significant differences in geothermal gradients across different sub-sags.Baiyun Sag has undergone two distinct periods of extensional process,the Eocene and Miocene,since the Cenozoic era.These two periods of heating and warming events have been identified,accelerating the maturation and evolution of source rocks.The main body of ancient basal heat flow value reached its highest at 13.82 Ma.The basin modelling results show that the maturity of source rocks is significantly higher in Baiyun main sub-sag than that in other sub-sags.The Eocene Wenchang Formation is currently in the stage of high maturity to over maturity,while the Eocene Enping Formation has reached the stage of maturity to high maturity.The rock thermal simulation experiment shows that the shallow lacustrine mudstone of the Wenchang Formation has a good potential of generating gas from kerogen cracking with high gas yield and long period of gas window.Shallow lacustrine mudstone of the Enping Formation has a good ability to generate light oil,and has ability to generate kerogen cracking gas in the late stage.The gas yield of shallow lacustrine mudstone of the Enping Formation is less than that of shallow lacustrine mudstone of the Wenchang Formation and the delta coal-bearing mudstone of the Enping Formation.The numerical simulation results indicate that the source rocks of Baiyun main sub-sag generate hydrocarbons earlier and have significantly higher hydrocarbon generation intensity than other sub-sags,with an average of about 1200×10^(4)t/km^(2).Oil and gas resources were mainly distributed in Baiyun main sub-sag and the main source rocks are distributed in the 3^(rd)and 4^(th)members of Wenchang Formation.Four favorable zones are selected for the division and evaluation of migration and aggregation units:No.(1)Panyu 30 nose-shaped structural belt,No.(3)Liuhua 29 nose-shaped uplift belt and Liwan 3 nose-shaped uplift belt,No.(2)gentle slope belt of Baiyun east sag,and No.(8)Baiyun 1 low-uplift.

Permeability Estimation of Shale Oil Reservoir with Laboratory-derived Data: A Case Study of the Chang 7 Member in Ordos Basin

The shale oil reservoir within the Yanchang Formations of Ordos Basin harbors substantial oil and gas resources and has recently emerged as the primary focus of unconventional oil and gas exploration and development.Due to its complex pore and throat structure,pronounced heterogeneity,and tight reservoir characteristics,the techniques for conventional oil and gas exploration and production face challenges in comprehensive implementation,also indicating that as a vital parameter for evaluating the physical properties of a reservoir,permeability cannot be effectively estimated.This study selects 21 tight sandstone samples from the Q area within the shale oil formations of Ordos Basin.We systematically conduct the experiments to measure porosity,permeability,ultrasonic wave velocities,and resistivity at varying confining pressures.Results reveal that these measurements exhibit nonlinear changes in response to effective pressure.By using these experimental data and effective medium model,empirical relationships between P-and S-wave velocities,permeability and resistivity and effective pressure are established at logging and seismic scales.Furthermore,relationships between P-wave impedance and permeability,and resistivity and permeability are determined.A comparison between the predicted permeability and logging data demonstrates that the impedance–permeability relationship yields better results in contrast to those of resistivity–permeability relationship.These relationships are further applied to the seismic interpretation of shale oil reservoir in the target layer,enabling the permeability profile predictions based on inverse P-wave impedance.The predicted results are evaluated with actual production data,revealing a better agreement between predicted results and logging data and productivity.

Nuclear magnetic resonance experiments on the time-varying law of oil viscosity and wettability in high-multiple waterflooding sandstone cores

A simulated oil viscosity prediction model is established according to the relationship between simulated oil viscosity and geometric mean value of T2spectrum,and the time-varying law of simulated oil viscosity in porous media is quantitatively characterized by nuclear magnetic resonance(NMR)experiments of high multiple waterflooding.A new NMR wettability index formula is derived based on NMR relaxation theory to quantitatively characterize the time-varying law of rock wettability during waterflooding combined with high-multiple waterflooding experiment in sandstone cores.The remaining oil viscosity in the core is positively correlated with the displacing water multiple.The remaining oil viscosity increases rapidly when the displacing water multiple is low,and increases slowly when the displacing water multiple is high.The variation of remaining oil viscosity is related to the reservoir heterogeneity.The stronger the reservoir homogeneity,the higher the content of heavy components in the remaining oil and the higher the viscosity.The reservoir wettability changes after water injection:the oil-wet reservoir changes into water-wet reservoir,while the water-wet reservoir becomes more hydrophilic;the degree of change enhances with the increase of displacing water multiple.There is a high correlation between the time-varying oil viscosity and the time-varying wettability,and the change of oil viscosity cannot be ignored.The NMR wettability index calculated by considering the change of oil viscosity is more consistent with the tested Amott(spontaneous imbibition)wettability index,which agrees more with the time-varying law of reservoir wettability.

Tectonic evolution and source rocks development of the super oil-rich Bohai Bay Basin,East China

The Bohai Bay Basin,as a super oil-rich basin in the world,is characterized by cyclic evolution and complex regional tectonic stress field,and its lifecycle tectonic evolution controls the formation of regional source rocks.The main pre-Cenozoic stratigraphic system and lithological distribution are determined through geological mapping,and the dynamics of the pre-Cenozoic geotectonic evolution of the Bohai Bay Basin are investigated systematically using the newly acquired high-quality seismic data and the latest exploration results in the study area.The North China Craton where the Bohai Bay Basin is located in rests at the intersection of three tectonic domains:the Paleo-Asian Ocean,the Tethys Ocean,and the Pacific Ocean.It has experienced the alternation and superposition of tectonic cycles of different periods,directions and natures,and experienced five stages of the tectonic evolution and sedimentary building,i.e.Middle–Late Proterozoic continental rift trough,Early Paleozoic marginal-craton depression carbonate building,Late Paleozoic marine–continental transitional intracraton depression,Mesozoic intracontinental strike-slip–extensional tectonics,and Cenozoic intracontinental rifting.The cyclic evolution of the basin,especially the multi-stage compression,strike-slip and extensional tectonics processes in the Hercynian,Indosinian,Yanshan and Himalayan since the Late Paleozoic,controlled the development,reconstruction and preservation of several sets of high-quality source rocks,represented by the Late Paleozoic Carboniferous–Permian coal-measure source rocks and the Paleogene world-class extra-high-quality lacustrine source rocks,which provided an important guarantee for the hydrocarbon accumulation in the super oil-rich basin.

Oil-source correlation and Paleozoic source rock analysis in the Siwa Basin,Western Desert:Insights from well-logs,Rock-Eval pyrolysis,and biomarker data

Understanding the origins of potential source rocks and unraveling the intricate connections between reservoir oils and their source formations in the Siwa Basin(Western Desert,Egypt)necessitate a thorough oil-source correlation investigation.This objective is achieved through a meticulous analysis of well-log responses,Rock-Eval pyrolysis,and biomarker data.The analysis of Total Organic Carbon across 31 samples representing Paleozoic formations in the Siwa A-1X well reveals a spectrum of organic richness ranging from 0.17 wt%to 2.04 wt%,thereby highlighting diverse levels of organic content and the presence of both Type II and Type III kerogen.Examination of the fingerprint characteristics of eight samples from the well suggests that the Dhiffah Formation comprises a blend of terrestrial and marine organic matter.Notably,a significant contribution from more oxidized residual organic matter and gas-prone Type III kerogen is observed.Contrarily,the Desouky and Zeitoun formations exhibit mixed organic matter indicative of a transitional environment,and thus featuring a pronounced marine influence within a more reducing setting,which is associated with Type II kerogen.Through analysis of five oil samples from different wells—SIWA L-1X,SIWA R-3X,SIWA D-1X,PTAH 5X,and PTAH 6X,it is evident that terrestrial organic matter,augmented by considerable marine input,was deposited in an oxidizing environment,and contains Type III kerogen.Geochemical scrutiny confirms the coexistence of mixed terrestrial organic matter within varying redox environments.Noteworthy is the uniformity of identified kerogen Types II and III across all samples,known to have potential for hydrocarbon generation.The discovery presented in this paper unveils captivating prospects concerning the genesis of oil in the Jurassic Safa reservoir,suggesting potential links to Paleozoic sources or even originating from the Safa Member itself.These revelations mark a substantial advancement in understanding source rock dynamics and their intricate relationship with reservoir oils within the Siwa Basin.By illuminating the processes of hydrocarbon genesis in the region,this study significantly enriches our knowledge base.

Effect of high-multiple water injection on rock pore structure and oil displacement efficiency

Experimental methods,including mercury pressure,nuclear magnetic resonance(NMR)and core(wateroil)displacement,are used to examine the effects of high-multiple water injection(i.e.water injection with high injected pore volume)on rock properties,pore structure and oil displacement efficiency of an oilfield in the western South China Sea.The results show an increase in the permeability of rocks along with particle migration,an increase in the pore volume and the average pore throat radius,and enhanced heterogeneity after high-multiple water injection.Compared with normal water injection methods,a high-multiple water injection is more effective in improving the oil displacement efficiency.The degree of recovery increases faster in the early stage due to the expansion of the swept area,and the transition from oil-wet to water-wet.The degree of recovery increases less in the late stage due to various factors,including the enhancement of heterogeneity in the rocks.Considering both the economic aspect and the production limit of water flooding,it is recommended to adopt other technologies to further enhance oil recovery after 300 PV water injection.

Application of C_(30)tetracyclic polyprenoids as effective biomarker in oil-to source rock correlation in the ZhuⅢdepression,Zhujiangkou Basin,northern South China

The northern South China Sea,including the Zhujiangkou Basin and the Beibuwan Basin,developed high-quality lacustrine source rocks during the Eocene rifting period.These source rocks are vital for hydrocarbon generation in the northern South China Sea.The ZhuⅠdepression in the Zhujiangkou Basin and the Beibuwan Basin typically exhibit high abundance of C_(30)4-methyl steranes.However,shales in the Eocene Wenchang Formation in the ZhuⅢdepression of the Zhujiangkou Basin contains lower quantities of high-quality lacustrine source rocks with 4-methyl steranes,which often co-elute with some pentacyclic triterpanes in gas chromatography-mass spectrometry(GC-MS).Therefore,the single 4-methylsterane parameter based on GC-MS cannot accurately distinguish organic source in the deep to semi-deep water lacustrine source rocks of the Wenchang Formation from other source rocks,thus impeding the recognition of their contributions to petroleum reservoirs.In this study,GC-MS of aliphatic hydrocarbons,palynofacies and algal identification,as well as stable carbon isotope data of organic matter were used to identify the algal species and construct the paleoclimate during deposition of the Wenchang Formation source rocks in the ZhuⅢdepression of the Zhujiangkou Basin.It is suggested that during the Wenchang Formation period,freshwater green algae prevailed in the lake,which is likely account for the relatively low content of 4-methyl steranes in the high-quality lacustrine source rocks.Controlled by the algal species,it is proposed that the content of C_(30)tetracyclic polyprenoids(TPP)can better indicate the quality of the Wenchang source rocks than C_(30)4-methyl steranes.Consequently,a relationship between the TPP index and the quality of the lacustrine source rocks in the Wenchang Formation of the ZhuⅢdepression was established.A higher TPP index indicates higher organic matter abundance and hydrogen index of the lacustrine source rocks.When applied to the origin analysis of oils in the ZhuⅢdepression,it is believed that the organic-rich deep lacustrine source rocks in the Wenchang Formation made great contribution to the transitional zone crude oils in the Wenchang A and Wenchang B depressions.

Dynamic simulation of differential accumulation history of deep marine oil and gas in superimposed basin:A case study of Lower Paleozoic petroleum system of Tahe Oilfield,Tarim Basin,NW China

According to the complex differential accumulation history of deep marine oil and gas in superimposed basins,the Lower Paleozoic petroleum system in Tahe Oilfield of Tarim Basin is selected as a typical case,and the process of hydrocarbon generation and expulsion,migration and accumulation,adjustment and transformation of deep oil and gas is restored by means of reservoine-forming dynamics simulation.The thermal evolution history of the Lower Cambrian source rocks in Tahe Oilfield reflects the obvious differences in hydrocarbon generation and expulsion process and intensity in different tectonic zones,which is the main reason controlling the differences in deep oil and gas phases.The complex transport system composed of strike-slip fault and unconformity,etc.controlled early migration and accumulation and late adjustment of deep oil and gas,while the Middle Cambrian gypsum-salt rock in inner carbonate platform prevented vertical migration and accumulation of deep oil and gas,resulting in an obvious"fault-controlled"feature of deep oil and gas,in which the low potential area superimposed by the NE-strike-slip fault zone and deep oil and gas migration was conducive to accumulation,and it is mainly beaded along the strike-slip fault zone in the northeast direction.The dynamic simulation of reservoir formation reveals that the spatio-temporal configuration of"source-fault-fracture-gypsum-preservation"controls the differential accumulation of deep oil and gas in Tahe Oilfield.The Ordovician has experienced the accumulation history of multiple periods of charging,vertical migration and accumulation,and lateral adjustment and transformation,and deep oil and gas have always been in the dynamic equilibrium of migration,accumulation and escape.The statistics of residual oil and gas show that the deep stratum of Tahe Oilfield still has exploration and development potential in the Ordovician Yingshan Formation and Penglaiba Formation,and the Middle and Upper Cambrian ultra-deep stratum has a certain oil and gas resource prospect.This study provides a reference for the dynamic quantitative evaluation of deep oil and gas in the Tarim Basin,and also provides a reference for the study of reservoir formation and evolution in carbonate reservoir of paleo-craton basin.

Oil-source rock correlation and quantitative assessment of Ordovician mixed oils in the Tazhong Uplift, Tarim Basin

The origin of the marine oils in the Tarim Basin has long been a disputed topic. A total of 58 DST （drill stem test） crude oil and 8 rock samples were investigated using a comprehensive geochemical method to characterize and identify the origin of the Ordovician oils in the Tazhong Uplift, Tarim Basin, northwest China. Detailed oil–oil and oil–source rock correlations show that the majority of the oils have typical biomarker characteristics of the Middle-Upper Ordovician （O2＋3） source rock and the related crude oil. These characteristics include a distinct ＂V-shaped＂ relative abundance of C27, C28 and C29 regular steranes, low abundance of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. Only a few oils display typical biomarker characteristics indicating the Cambrian–Lower Ordovician （∈-O1） genetic affinity, such as linear or anti ＂L＂ shape distribution of C27, C28 and C29 regular sterane, with relatively high concentrations of dinosterane, 24-norcholestanes, triaromatic dinosteroids and gammacerane. It appears that most of the Ordovician oils in the Tazhong Uplift were derived from the O2＋3 intervals, as suggested by previous studies. However, the compound specific n-alkane stable carbon isotope data indicate that the Ordovician oils are mixtures from both the ∈-O1 and O2＋3 source rocks rather than from the O2＋3 strata alone. It was calculated that the proportion of the∈-O1 genetic affinity oils mixed is about 10.8%-74.1%, with an increasing trend with increasing burial depth. This new oil-mixing model is critical for understanding hydrocarbon generation and accumulation mechanisms in the region, and may have important implications for further hydrocarbon exploration in the Tarim Basin.

Theoretical Progress and Key Technologies of Onshore Ultra-Deep Oil/Gas Exploration

Oil/gas exploration around the world has extended into deep and ultra-deep strata because it is increasingly difficult to find new large-scale oil/gas reservoirs in shallow–middle buried strata. In recent years, China has made remarkable achievements in oil/gas exploration in ultra-deep areas including carbonate and clastic reservoirs. Some (ultra) large-scale oil and gas fields have been discovered. The oil/gas accumulation mechanisms and key technologies of oil/gas reservoir exploration and development are summarized in this study in order to share China’s experiences. Ultra-deep oil/gas originates from numerous sources of hydrocarbons and multiphase charging. Liquid hydrocarbons can form in ultradeep layers due to low geothermal gradients or overpressures, and the natural gas composition in ultra-deep areas is complicated by the reactions between deep hydrocarbons, water, and rock or by the addition of mantle- or crust-sourced gases. These oils/gases are mainly stored in the original highenergy reef/shoal complexes or in sand body sediments. They usually have high original porosity. Secondary pores are often developed by dissolution, dolomitization, and fracturing in the late stage. The early pores have been preserved by retentive diageneses such as the early charging of hydrocarbons. Oil/gas accumulation in ultra-deep areas generally has the characteristics of near-source accumulation and sustained preservation. The effective exploration and development of ultra-deep oil/gas reservoirs depend on the support of key technologies. Use of the latest technologies such as seismic signal acquisition and processing, low porosity and permeability zone prediction, and gas–water identification has enabled the discovery of ultra-deep oil/gas resources. In addition, advanced technologies for drilling, completion, and oil/gas testing have ensured the effective development of these fields.

Application of Biomarkers to Quantitative Source Assessment of Oil Pools

Recent detailed organic geochemical and geological investigation indicate that oils of the Bamianhe oilfield, Bohai Bay Basin, East China are the mixture of less mature oils and normal oils derived from the ES4 mudstones and shales with a wide range of thermal maturity from immature to middle-maturity, and most of the oils were proved to be sourced from the depocenter of the Niuzhuang Sag immediately adjacent to the Bamianhe oilfield. Two approaches to quantify the amount of immature oils mixed through quantitative biomarkers were established. One is a relatively simple way only through organic geochemical analysis while the other is to be combined with basin modeling. Selecting biomarkers as proxies is the crucial point in both of them. The results show that the less mature oils mixed in the Bamianhe oilfield is less than 10% and 18% respectively based on the two approaches, which coincide with the results of oil-source rock correlation.

Evidence of Oil Sources and Migration in Triassic-Jurassic Reservoirs in the South Tianhuan Depression of the Ordos Basin, China Based on Analysis of Biomarkers and Nitrogen-Bearing Compounds

The Ordos Basin is an important intracontinental sedimentary basin in western China for its abundant Mesozoic crude oil resources. The southern part of the Tianhuan Depression is located in the southwestern marginal area of this Basin, in which the Jurassic and Triassic Chang-3 are the main oil-bearing strata. Currently, no consensus has been reached regarding oil source and oil migration in the area, and an assessment of oil accumulation patterns is thus challenging. In this paper, the oil source, migration direction, charging site and migration pathways are investigated through analysis of pyrrolic nitrogen compounds and hydrocarbon biomarkers. Oil source correlations show that the oils trapped in the Jurassic and Chang-3 reservoirs were derived from the Triassic Chang-7 source rocks. The Jurassic and Chang-3 crude oils both underwent distinct vertical migration from deep to shallow strata, indicating that the oils generated by Chang-7 source rocks may have migrated upward to the shallower Chang-3 and Jurassic strata under abnormally high pressures, to accumulate along the sand bodies of the ancient rivers and the unconformity surface. The charging direction of the Jurassic and Chang-3 crude oils is primarily derived from Mubo, Chenhao, and Shangliyuan, which are located northeast of the southern Tianhuan Depression, with oils moving toward the west, southwest, and south. The results show that an integration of biomarker and nitrogen-bearing compound analyses can provide useful information about oil source, migration, and accumulation.

A review of carbonates as hydrocarbon source rocks: basic geochemistry and oil–gas generation

Carbonates have been known to act as hydrocarbon source rocks, but their basic geochemical and associated hydrocarbon generation characteristics remain not well understood as they occur with argillaceous source rocks in most cases, and the hydrocarbon generation from each rock type is di cult to distinguish, forming one of puzzling issues within the field of petroleum geology and geochemistry. To improve the understanding of this critical issue, this paper reviews recent advances in this field and provides a summary of key areas that can be studied in future. Results show that carbonate source rocks are generally associated with high-salinity environments with low amounts of terrestrial inputs and low dissolved oxygen contents. Petrographically, these source rocks are dark gray or black, fine-grained, stratified, and contain bacterial and algal bioprecursors along with some other impurities. They generally have low organic matter contents, although these can vary significantly in di erent cases(e.g., the total organic carbon contents of marine and lacustrine carbonate source rocks in China are generally 0.1%–1.0% and 0.4%–4.0%, respectively). These rocks contain type I and type II kerogen, meaning there is a lack of vitrinites. This means that assessment of the maturity of the organic matter in these sediments needs to use non-traditional techniques rather than vitrinite reflectance. In terms of molecular geochemistry, carbonate source rocks have typical characteristics indicative of generally reducing and saline environments and lower organism-dominated bioprecursors of organic matter, e.g., high contents of sulfur compounds, low Pr/Ph ratios, and dominance of n-alkanes. Most of the carbonate source rocks are typically dominated by D-type organic facies in an oxidized shallow water mass, although high-quality source rocks generally contain A-and B-type organic facies in saline lacustrine and marine-reducing environments, respectively. The hydrocarbon generation model for the carbonate source rocks can involve early, middle, and late stages, with a diversity of hydrocarbons within these rocks, which can be aggregated, adsorbed, enclosed within minerals, or present as inclusions. This in turn implies that the large-scale hydrocarbon expulsion from these rocks is reliant on brittle deformation caused by external forces. Finally, a number of aspects of these source rocks remain unclear and need further study, including the e ectiveness of carbonates as hydrocarbon source rocks, bioprecursors, and hydrocarbon generation models of carbonate source rock, and the di erences between marine and lacustrine carbonate source rocks.

Geochemical studies of the Silurian oil reservoir in the Well Shun-9 prospect area, Tarim Basin, NW China

Commercial oil flow has been obtained from the sandstone reservoir of the Lower Silurian Kelpintag Formation in the Well Shun-9 prospect area.In the present studies,10 Silurian oil and oil sand samples from six wells in the area were analyzed for their molecular and carbon isotopic compositions,oil alteration（biodegradation）,oil source rock correlation and oil reservoir filling direction.All the Silurian oils and oil sands are characterized by low Pr/Ph and C21/C23 tricyclic terpane（〈1.0） ratios,＂V＂-pattern C27-C29 steranes distribution,low C28-sterane and triaromatic dinosterane abundances and light δ13C values,which can be correlated well with the carbonate source rock of the O3 l Lianglitage Formation.Different oil biodegradation levels have also been confirmed for the different oils/oil sands intervals.With the S1k2 seal,oils and oil sands from the S1k1 interval of the Kelpintag Formation have only suffered light biodegradation as confirmed by the presence of ＂UCM＂ and absence of 25-norhopanes,whereas the S1k3-1 oil sands were heavily biodegraded（proved by the presence of 25-norhopanes） due to the lack of the S1k2 seal,which suggests a significant role of the S1k2 seal in the protection of the Silurian oil reservoir.Based on the Ts/（Ts＋Tm） and 4-/1-MDBT ratios as reservoir filling tracers,a general oil filling direction from NW to SE has been also estimated for the Silurian oil reservoir in the Well Shun-9 prospect area.

Oil Source and Entrapment Epoch of the Ordovician Oil Reservoir in the Kongxi Burial-Hill Zone, Huanghua Depression, North China

An oil flow obtained from the Middle Ordovician Fengfeng Formation carbonate reservoir in the well KG-3, Kongxi burial-hill zone in 1993 marked a breakthrough in petroleum exploration of the high-mature Lower Palaeozoic strata, North China. Both the Lower member of the Fengfeng Formation and the Second Member of the Upper Majiagou Formation in the Middle Ordovician are supposed to be the main source beds. Oil generation peaks range from 1.0% to 1.6% in Ro, showing a “lag effect” of oil generation in high-mature carbonate source rocks under multicyclic tectonic movement conditions. The Kongxi burial-hill zone adjoins a potential Ordovician source kitchen. The KG-3 Ordovician burial-hill reservoir has undergone two oil filling events, i.e., an early event in the Late Carboniferous-Permian and a more significant late event in the early Eogene.

Characteristics and Evaluation of the High-Quality Source Rocks of Cretaceous Continental Shale Oil in Tonghua Basin, China

The presence of shale oil in the Cretaceous Hengtongshan Formation in the Tonghua Basin, drilled by the well TD-01, has been discussed in this geological investigation for the first time. To evaluate the high-quality source rocks of Cretaceous continental shale oil, the distribution characteristics and the evolution of the ancient environment, samples of shale were systematically analyzed in terms of sedimentary facies, organic geochemistry, and organic carbon isotopic composition. The results demonstrate that a TOC value of 1.5% represents the lower-limit TOC value of the high-quality source rocks. Source rocks have an aggregate thickness of 211 m and contain abundant organic matter, with TOC values of 2.69% on average and a maximum value over 5.44%. The original hydrocarbon-generative potential value(S_1+S_2) is between 0.18 mg/g and 6.13 mg/g, and the Ro is between 0.97% and 1.40%. The thermal maturation of the source rocks is relatively mature to highly mature. The δ^(13)C value range is between -34.75‰ and -26.53‰. The ratio of saturated hydrocarbons to aromatic hydrocarbons is 1.55 to 5.24, with an average of 2.85, which is greater than 1.6. The organic types are mainly type Ⅱ_1, followed by type Ⅰ. The organic carbon source was C_3 plants and hydrophytes. The paleoclimate of the Hengtongshan Formation can be characterized as hot and dry to humid, and these conditions were conducive to the development of high-quality source rocks. A favorable paleoenvironment and abundant organic carbon sources provide a solid hydrocarbon generation base for the formation and accumulation of oil and gas in the shale of the Tonghua Basin.

Spatial-temporal coupling between high-quality source rocks and reservoirs for tight sandstone oil and gas accumulations in the Songliao Basin, China

The spatial-temporal relationship between high-quality source rocks and reservoirs is a key factor when evaluating the formation,occurrence,and prospectivity of tight oil and gas reservoirs.In this study,we analyze the fundamental oil and gas accumulation processes occurring in the Songliao Basin,contrasting tight oil sand reservoirs in the south with tight gas sand reservoirs in the north.This is done using geochemical data,constant-rate and conventional mercury injection experiments,and fluid inclusion analyses.Our results demonstrate that as far as fluid mobility is concerned,the expulsion center coincides with the overpressure zone,and its boundary limits the occurrence of tight oil and gas accumulations.In addition,the lower permeability limit of high-quality reservoirs,controlled by pore-throat structures,is 0.1×10^-3μm^2 in the fourth member of the Lower Cretaceous Quantou Formation(K1q^4)in the southern Songliao Basin,and 0.05×10^-3μm^2 in the Lower Cretaceous Shahezi Formation(K1sh)in the northern Songliao Basin.Furthermore,the results indicate that the formation of tight oil and gas reservoirs requires the densification of reservoirs prior to the main phase of hydrocarbon expulsion from the source rocks.Reservoir“sweet spots”develop at the intersection of high-quality source rocks(with high pore pressure)and reservoirs(with high permeability).