Hydrocarbon Exploration Potential Research Articles

Sequence stratigraphy, sedimentary systems and implications for hydrocarbon exploration in the northern Xujiaweizi Fault Depression, Songliao Basin, NE China

Recent drilling data from the northern Songliao Basin reveal considerable hydrocarbon exploration potential in deep-seated small-scale faulted basins. In this paper, the Shahezi Formation of the northern Xujiaweizi Fault Depression within the Songliao Basin was investigated as a case study. Sequence stratigraphy, sedimentary systems and the hydrocarbon exploration potential of the small-scale faulted basin were investigated through observations and descriptions of cores; analyses of conventional log curves, imaging data and logging data; and interpretations of 3-D seismic profiles. Four third-order sequences, mainly controlled by sediment supply and fault activity, were identified based on unconformities at the basin margins and in sedimentary successions. System tracts in the third-order sequences were also recognized through lithological associations and geophysical response characteristics. The distributions of sedimentary systems, including fan deltas, braided deltas, lacustrine deposits, subaqueous fans, volcaniclastic deposits and incised-valley deposits, in the sequence framework are associated with basin evolution. During the early stage of the Shahezi Formation (SQ1 and SQ2), the sedimentary area was mainly covered by fan deltas, and lacustrine deposits were not very developed. Additionally, incised-valley systems formed on basin margins and subaqueous fans formed along basin-controlled faults. During the middle stage (SQ3), fan delta deposits on gentle slopes were gradually replaced by braided delta deposits, and the sizes of lacustrine facies increased with basin expansion. In the late stage (SQ4), the basin and lacustrine deposit areas reached their maximum sizes, and braided deltas became the dominant sedimentary systems on gentle slopes. With continuous sediment supply, fan and braided deltas migrated forward, and the lacustrine system was locally distributed. In this small-scale faulted basin, the lacustrine mudstones and coal seams widely developed in SQ4, especially in SQ4-HST, and they also exhibited good source rock properties for gas generation. Sandbodies of fan deltas and braided deltas in the upper Shahezi Formation, exhibiting good contact relationships with underlying source rocks, can be favourable reservoirs for hydrocarbon accumulation, as confirmed by the newly drilled Well Songs9H (with a daily gas production of 20×104 m3). However, due to low porosity and permeability (averages of 4.7% and 0.28×10−3µm2, respectively), these reservoirs may need fracturing for commercial hydrocarbon production.

Hydrocarbon accumulation in the deep waters of South China Sea controlled by the tectonic cycles of marginal sea basins

AbstractThe tectonic cycle of the marginal sea basins in South China Sea (SCS) includes two cycles, i.e., the formation and contraction of Palaeo-SCS and Neo-SCS. The northern part of SCS is a rift basin on a passive continental margin, while the the Nansha Block is a drifting rift basin. The southern part is a compound compressional basin on an active continental margin; the western part is a shear-extensional basin on a transform continental margin; the eastern part is an accretionary wedge basin on a subduction continental margin. The deep-water basins are mainly distributed on the continental slope and the the Nansha Block. There are three sets of source rocks in the deep-water areas of the northern continental margin in SCS, i.e., Eocene terrestrial facies, early Oligocene transitional facies and late Oligocene marine facies. A set of Late Cretaceous-Early Oligocene terrestrial marine facies source rocks are developed in the drift-rift basin of SCS. Three sets of Oligocene, early Miocene and Mid-Miocene marine-terrestrial transitional facies source rocks are developed in the deep-water areas of both the southern and western continental margins of SCS. Four sets of reservoirs developed in the northern deep waters of SCS are dominated by deep sea fans. Two sets of reservoirs developed in the the Nansha Block are dominated by delta and biogenic reef. The southern part of SCS is dominated by deep sea fan and biogenic reef. Reservoirs of large channels and other clastic facies were developed in front of the estuaries, while biogenic reef bank was formed in the uplift zone. The hydrocarbon accumulation assemblages are mainly presented as Oligocene-Pliocene in the deep waters on the northern continental margin of SCS, Eocene-Lower Oligocene in the the Nansha Block, Oligocene-Pliocene and Oligocene-Miocene in the deep waters on the southern and western continental margin of SCS, respectively. The major hydrocarbon reservoir types in the deep waters of SCS are related to structural traps, deep water fans and biogenic reefs. The formation of basin, hydrocarbon and reservoir in the deep waters of SCS are controlled by the tectonic cycles of the marginal sea basins, revealing a great potential for hydrocarbon exploration.

Tectono-sedimentary and hydrocarbon potential analysis of rift-related successions in the Dehui Depression, Songliao Basin, Northeastern China

In this study, we use seismic reflection, well-log and core data to investigate the basin structure and sedimentary filling of the Upper Jurassic and Lower Cretaceous in the Dehui Depression, Songliao Basin, Northeastern China. The Late Jurassic-Early Cretaceous Dehui Depression is an active-fault bounded graben. Unconformity and vertical variations on fault activity reveal that the syn-rift stage of the basin can be subdivided into four sub-stages: (i) early syn-rift stage (Huoshiling Formation), which is composed mainly of fan-delta and shallow lacustrine depositional systems; (ii) rift-climax stage (Shahezi Formation), which consists of sublacustrine fan, fan-delta and deep lacustrine depositional systems; (iii) late syn-rift stage (Yingcheng Formation), which is composed of fan-delta and shallow lacustrine depositional systems; (iv) rift-depression transition stage (Denglouku Formation), which is composed of braid delta and shallow lacustrine depositional systems. Fault evolution and episodic rifting control the basin geomorphology, and thus influenced the depositional systems of each stage, while the climate influenced the sediment type. Besides, our estimation on the hydrocarbon exploration potential of the rift-related successions in Dehui Depression shows that they can sustain the formation of medium-large gasfield.

Lower limit of hydrocarbon accumulation in the Kuqa Depression, Tarim Basin, NW China

The lower limit of hydrocarbon accumulation in the Kuqa Depression is investigated. The Kuqa Depression in the Tarim Basin is one of the largest gas-producing regions in China. High yields of hydrocarbons have been found in depths below 7000 m, which suggests that the deep strata have great potential for hydrocarbon exploration. However, for effective deep exploration, the effective limits such as maximum depth or minimum physical properties of reservoirs have not yet been established. The lower limit of hydrocarbon accumulation, i.e. the conditions at which hydrocarbon accumulation is no longer possible, is determined by analysing the characteristics of effective reservoir space, reservoir permeability, fluid potential differences inside and outside the reservoir, and drilling results of exploratory wells in actual geological conditions. Research shows that the lower limit of hydrocarbon accumulation is reached when irreducible water saturation reaches 100%, reservoir permeability reaches as low as 0.01 × 10−3 µm2, fluid potential ratio of outside to inside the reservoir (fluid potential ratio of the surrounding rock to sandstone reservoir) is less than 5.5, and exploratory wells reach reservoirs that are all dry layers. From these four aspects, the lower limit of hydrocarbon accumulation corresponds with reservoir porosity of approximately 2.5%, permeability of approximately 0.01 × 10−3 µm2, pore throat radius of approximately 0.003–0.004 µm, and burial depth of approximately 8200 m. Determining the lower limit of hydrocarbon accumulation in the Kuqa Depression will contribute to predicting favourable exploration areas and evaluating effective resources. Copyright © 2016 John Wiley & Sons, Ltd.

Ultra-deep liquid hydrocarbon exploration potential in cratonic region of the Tarim Basin inferred from gas condensate genesis

A suite of gas condensate and crude oil samples from cratonic region of the Tarim Basin has been analyzed by routine GC–MS technique to elucidate their molecular compositions and genetic origins. Maturity parameters derived from biomarkers, aromatic hydrocarbons and diamondoids suggest very different maturity ranges for both condensates and oils, implying different stages of hydrocarbon emplacement and entrapment. Similar maturity range in two sample types without depth control suggests that condensates and oils are genetically close but different in gas oil ratios. Using diamondoid concentrations as a measure of loss of oil due to cracking indicates that majority condensates are not formed by thermal cracking of oils. The key controls on hydrocarbon phases are multiple charges and subsequent dysmigration. Thermal cracking and thermochemical sulfate reduction occur mainly at the depth deeper than current penetration (around 7000m). The window of liquid hydrocarbon preservation may be shifted towards greater depths and previously unrecognized deep-basin oil and condensate resources are expected.

Modelling petroleum generation of Late Cretaceous Dabut Formation in the Jiza-Qamar Basin, Eastern Yemen

The Jiza-Qamar Basin in eastern Yemen is still undergoing hydrocarbon exploration and hydrocarbon potential has not been assigned yet. In this study, subsurface samples from two onshore and offshore wells were collected to characterize the source rocks of Dabut Formation and to incorporate into basin modelling in order to know and determine the timing of petroleum generation and expulsion of the Dabut source rocks. Based on organic geochemical analysis, the Dabut sediments have variable TOC content in the range of 0.5–2.5 wt%, indicating fair to good source rock generative potential. The organic matter of Dabut source rock is dominated by Type III kerogen with minor mixed III–II kerogen contributions, and is thus considered to be mainly gas-prone and some oil-prone. This is supported by HI values in the range of 50–212 mg HC/g TOC. Vitrinite reflectance in the range of 0.63–0.88%Ro and pyrolysis Tmax in the range of 427–454 °C, generally indicate that the Dabut source rocks contain mature organic matter.One-dimensional basin modelling was performed to analyse the hydrocarbon generation and expulsion history of the Dabut source rocks in the Jiza-Qamar Basin based on the reconstruction of the burial and thermal maturity histories in order to improve our understanding of the hydrocarbon generation potential. Calibration of the model with measured vitrinite reflectance (%Ro) and borehole temperature (BHT) data indicates that the paleo-heat-flow was constant during the Late Cretaceous–Paleogene but increased during the Late Paleogene–Neogene and then decreased exponentially from Neogene to present-day.The modelled maturity history predicts that the oil generation (0.5% Ro) in the Dabut source rock began from about 56 Ma to 42 Ma and the peak hydrocarbon generation (0.86% Ro) occurred approximately from 14 Ma to 13 Ma. These models also indicate that the main phase of oil generation was at 56 Ma to 25 Ma, whereas the main phase of gas generation began from about 25 Ma to 14 Ma and still generated in the present-day.

Fluid environment for preservation of pore spaces in a deep dolomite reservoir

AbstractWell TS1 reveals many uncemented pores and vugs at depths of more than 8000 m in a deep Cambrian dolomite reservoir in the Tarim Basin, northwestern China. The fluid environment and mechanism required for the preservation of reservoir spaces have yet not been well constrained. Carbon, oxygen, and strontium isotope compositions and fluid inclusion data suggest two types of fluids, meteoric water and hydrothermal fluid, affecting the Lower Paleozoic carbonate reservoirs in the Tarim Basin. Based on simulation using a thermodynamic model for H2O‐CO2‐NaCl‐CaCO3 system, meteoric water has the ability to continuously dissolve carbonate minerals during downward migration from the surface to deep strata until it reaches a transition depth, below which it will begin to precipitate carbonate minerals to fill preexisting pore spaces. In contrast, hydrothermal fluid has the ability to dissolve carbonate in deep strata and precipitate carbonate in shallow strata during upward migration. Based on the dissolution–precipitation characteristics of the two types of fluids, the ideal fluid environment for the preservation of preexisting reservoir spaces occurs when carbonate reservoir is neither in the CaCO3 precipitation domain of meteoric water nor in the CaCO3 precipitation domain of hydrothermal fluid. Taking the Lower Paleozoic carbonate reservoirs in the north uplift area as an example, the spaces in the deep Cambrian dolomite reservoir near well TS1 were seldom filled because thick Ordovician deposits blocked meteoric water from migrating downward into the Cambrian dolomite reservoir and because the Cambrian dolomite reservoir has been in the domain of hydrothermal dissolution since the Permian. The deep carbonate layers in basins elsewhere with a similar fluid environment may have high uncemented porosity and consequently have good hydrocarbon exploration potential.

An analysis of natural gas exploration potential in the Qiongdongnan Basin by use of the theory of “joint control of source rocks and geothermal heat”

The Oligocene Yacheng Fm contains the most important source rocks that have been confirmed by exploratory wells in the Qiongdongnan Basin. The efficiency of these source rocks is the key to the breakthrough in natural gas exploration in the study area. This paper analyzes the hydrocarbon potential of each sag in this basin from the perspective of control of both source rocks and geothermal heat. Two types of source rocks occur in the Yacheng Fm, namely mudstone of transitional facies and mudstone of neritic facies. Both of them are dominated by a kerogen of type-III, followed by type-II. Their organic matter abundances are controlled by the amount of continental clastic input. The mudstone of transitional facies is commonly higher in organic matter abundance, while that of neritic facies is lower. The coal-measure source rocks of transitional facies were mainly formed in such environments as delta plains, coastal plains and barrier tidal flat-marshes. Due to the control of Cenozoic lithosphere extension and influence of neotectonism, the geothermal gradient, terrestrial heat flow value (HFV) and level of thermal evolution are generally high in deep water. The hot setting not only determines the predominance of gas generation in the deep-water sags, but can promote the shallow-buried source rocks in shallow water into oil window to generate oil. In addition to promoting the hydrocarbon generation of source rocks, the high geothermal and high heat flow value can also speed up the cracking of residual hydrocarbons, thus enhancing hydrocarbon generation efficiency and capacity. According to the theory of joint control of source quality and geothermal heat on hydrocarbon generation, we comprehensively evaluate and rank the exploration potentials of major sags in the Qiongdongnan Basin. These sags are divided into 3 types, of which type-I sags including Yanan, Lingshui, Baodao, Ledong and Huaguang are the highest in hydrocarbon exploration potential.

ON EXPLORATION POTENTIAL AND NEW OIL DISCOVERIES IN VOLKOV-GUROV HORST SYSTEM

The exploration maturity of the Republic of Bashkortostan in terms of the remaining petroleum potential is characterized among other features by the fact that the undiscovered oil and gas resources are confined to small traps with complex architecture. Quite high hydrocarbon exploration potential of the Devonian sandstones as well as younger reservoirs is still related to the known extensive faulted zones. The paper focuses on one of such zones namely the Volkov-Gurov Horst System (VGHS). The available geological and geophysical data suggest that this structural tectonic zone has additional potential for new oil discoveries. Fairly promising are not only the up thrown blocks of the VGHS which are characterized by very uneven drilling density, but also a deeper trend of anticlines along the downthrown wall of the fault to the South-East of it. Evidence thereof is provided by the geological setting of the two oil discoveries made in the Devonian sandstones allied to the VGHS play fairway. The first discovery was made in the sandstones of Pashiy DI Fm. in the NE part of the study area within the Volkov-Gurov Horst System. Drilling data indicates that the top of the productive sandstone reservoir in well 37POD lies at -1951 m TVDss 52 m deeper than in well 231AMT (-1899 m) drilled in the up thrown horst block, the formation was water-bearing in that well. The fact that no oil was found in the shallow part of the reservoir may imply a 3-way dip closure sealed to a fault or impermeable tectonic barrier. The second discovery is considerably to the SW on the Baskakov area of Novo-Uzhybashevskoe field. Well 7UZB penetrated top of Kynov Fm. at the shallowest depth of –1885 m, i.e. 7 and 13 m above the same formation penetrated in wells 475 (-1892 m) and 25UZB (-1898 m) accordingly which found oil. The above mentioned arguments and the potential traps identified on the 2D seismic sections contribute to the additional exploration potential and commercial reserves of oil yet to be found in the sandstones of Kynov Dkn, Pashiy DI and Mullin DII formations not only on the up thrown fault blocks of the VGHS but also anticlines along the downthrown SE wall of the reverse fault bounding the graben in deeper-seated reservoirs.

Evolutionary characteristics of the sags to the east of Tan–Lu Fault Zone, Bohai Bay Basin (China): Implications for hydrocarbon exploration and regional tectonic evolution

Some Cenozoic half-grabens (sags) have been found to the east of the Tan–Lu Fault Zone in the Bohai Bay Basin, east China. The evolutionary history of these sags is consistent with the entire Bohai Bay Basin; besides, some remarkable characteristics which had not been mentioned in previous studies of the Bohai Bay Basin are presented, and they are the keys to understand the regional tectonic evolution. Among them, two characteristics are emphasized: (1) the structural and evolutionary features of the sags were markedly changed at about 38Ma; (2) the Paleogene basin underwent several times of uplifts and denudations during Paleogene. The first characteristic shows that the normal faulting was the dominant structural deformation before 38Ma, and after then, the strike-slip movement might initiate to influence the basin. The second characteristic indicates remarkable reducing of the present-day residual basin relative to the original basin and, implies the episodic uplifting of the Jiaoliao massif. Besides, our estimation on the hydrocarbon exploration potential of these sags shows that part of them can sustain the formation of medium-large oilfield independently, while, part can contribute to the formation of large oilfield.

Dynamic Field Division of Hydrocarbon Migration, Accumulation and Hydrocarbon Enrichment Rules in Sedimentary Basins

Abstract:Hydrocarbon distribution rules in the deep and shallow parts of sedimentary basins are considerably different, particularly in the following four aspects. First, the critical porosity for hydrocarbon migration is much lower in the deep parts of basins: at a depth of 7000 m, hydrocarbons can accumulate only in rocks with porosity less than 5%. However, in the shallow parts of basins (i.e., depths of around 1000 m), hydrocarbon can accumulate in rocks only when porosity is over 20%. Second, hydrocarbon reservoirs tend to exhibit negative pressures after hydrocarbon accumulation at depth, with a pressure coefficient less than 0.7. However, hydrocarbon reservoirs at shallow depths tend to exhibit high pressure after hydrocarbon accumulation. Third, deep reservoirs tend to exhibit characteristics of oil (–gas)–water inversion, indicating that the oil (gas) accumulated under the water. However, the oil (gas) tends to accumulate over water in shallow reservoirs. Fourth, continuous unconventional tight hydrocarbon reservoirs are distributed widely in deep reservoirs, where the buoyancy force is not the primary dynamic force and the caprock is not involved during the process of hydrocarbon accumulation. Conversely, the majority of hydrocarbons in shallow regions accumulate in traps with complex structures. The results of this study indicate that two dynamic boundary conditions are primarily responsible for the above phenomena: a lower limit to the buoyancy force and the lower limit of hydrocarbon accumulation overall, corresponding to about 10%–12% porosity and irreducible water saturation of 100%, respectively. These two dynamic boundary conditions were used to divide sedimentary basins into three different dynamic fields of hydrocarbon accumulation: the free fluid dynamic field, limit fluid dynamic field, and restrain fluid dynamic field. The free fluid dynamic field is located between the surface and the lower limit of the buoyancy force, such that hydrocarbons in this field migrate and accumulate under the influence of, for example, the buoyancy force, pressure, hydrodynamic force, and capillary force. The hydrocarbon reservoirs formed are characterized as “four high,” indicating that they accumulate in high structures, are sealed in high locations, migrate into areas of high porosity, and are stored in reservoirs at high pressure. The basic features of distribution and accumulation in this case include hydrocarbon migration as a result of the buoyancy force and formation of a reservoir by a caprock. The limit fluid dynamic field is located between the lower limit of the buoyancy force and the lower limit of hydrocarbon accumulation overall; the hydrocarbon migrates and accumulates as a result of, for example, the molecular expansion force and the capillary force. The hydrocarbon reservoirs formed are characterized as “four low,” indicating that hydrocarbons accumulate in low structures, migrate into areas of low porosity, and accumulate in reservoirs with low pressure, and that oil(–gas)–water inversion occurs at low locations. Continuous hydrocarbon accumulation over a large area is a basic feature of this field. The restrain fluid dynamic field is located under the bottom of hydrocarbon accumulation, such that the entire pore space is filled with water. Hydrocarbons migrate as a result of the molecular diffusion force only. This field lacks many of the basic conditions required for formation of hydrocarbon reservoirs: there is no effective porosity, movable fluid, or hydrocarbon accumulation, and potential for hydrocarbon exploration is low. Many conventional hydrocarbon resources have been discovered and exploited in the free fluid dynamic field of shallow reservoirs, where exploration potential was previously considered to be low. Continuous unconventional tight hydrocarbon resources have been discovered in the limit fluid dynamic field of deep reservoirs; the exploration potential of this setting is thought to be tremendous, indicating that future exploration should be focused primarily in this direction.

The Depositional System of Dongying Formation and Subtle Reservoir Exploration in Sha’nan Structural Belt Qikou Sag of Bohai Bay Basin, China

The subtle reservoir has become an important exploration target within the Bohai Bay Basin, especially in the Qikou sag. In order to guide subtle reservoirs exploration in offshore area geological analysis to Sha’nan structural belt is carried out in this paper. Qikou sag has large thickness, high abundance, ideal type hydrocarbon source rock. By unconformity recognition technique and paleotectonic analysis technique, results show that tectonic uplift had provided sedimentary source to the depression around it after Es1. By 3-D seismic interpretation technique and Seismic facies analysis, the sedimentary facies was confirmed. Geological analysis results show that sand bar, subaqueous fan is developed around it in Ed3. With the new geological analysis data sedimentary model of Sha’nan structural belt has been built in this paper. The sand bar and subaqueous fans showed a good reservoir potential, which are advantageous to oil accumulations. The southern part of Sha’nan structural belt has good hydrocarbon exploration potential.

Formation of Natural Bitumen and its Implication for Oil/gas Prospect in Dabashan Foreland

Abstract:Natural bitumen is the evolutionary residue of hydrocarbon of sedimentary organic matter. Several kinds of bitumen with different occurrences, including bitumen in source rock, migration bitumen filled in fault, oil‐bed bitumen and paleo‐reservoir bitumen, are distributed widely in the Dabashan foreland. These kinds of bitumen represent the process of oil/gas formation, migration and accumulation in the region. Bitumen in source rock filled in fractures and stylolite and experienced deformation simultaneously together with source rock themselves. It indicated that oil/gas generation and expelling from source rock occurred under normal buried thermal conditions during prototype basin evolution stages prior to orogeny. Occurrences of bitumen in source rock indicated that paleoreservoir formation conditions existed in the Dabashan foreland. Migration bitumen being widespread in the fault revealed that the fault was the main channel for oil/gas migration, which occurred synchronously with Jurassic foreland deformation. Oil‐bed bitumen was the kind of pyrolysis bitumen that distributed in solution pores of reservoir rock in the Dabashan foreland depression, the northeastern Sichuan Basin. Geochemistry of oil‐bed bitumen indicated that natural gas that accumulated in the Dabashan foreland depression formed from liquid hydrocarbon by pyrolysis process. However, paleo‐reservior bitumen in the Dabashan forleland was the kind of degradation bitumen that formed from liquid hydrocarbon within the paleo‐reservior by oxidation, alteration and other secondary changes due to paleo‐reservior damage during tectonics in the Dabashan foreland. In combination with the tectonic evolution of the Dabashan foreland, it is proposed that the oil/gas generated, migrated and accumulated to form the paleo‐reservoir during the Triassic Indosinian tectonic movement. Jurassic collision orogeny, the Yanshan tectonic movement, led to intracontinental orogeny of the Dabashan area accompanied by geofluid expelling and paleo‐reservoir damage in the Dabashan foreland. The present work proposed that there is liquid hydrocarbon exploration potential in the Dabashan foreland, while there are prospects for the existence of natural gas in the Dabashan foreland depression.

Characteristics of hydrocarbon accumulation and exploration potential of the northern South China Sea deepwater basins

Although the huge potential of the northern South China Sea deepwater basins has been proven by a series of discoveries that followed the exploration breakthrough of well LW 3-1-1, recent drilling and other studies have demonstrated the uniqueness and complicated nature of hydrocarbon accumulations of the deepwater basins there. Based on a review of previous work and the latest exploration activities and studies, the purpose of this paper is to discuss the critical controls for hydrocarbon accumulations in the deepwater basins of the northern South China Sea. A terrestrial-marine transitional coal-bearing source rock is proposed to be the primary source rock for the deepwater basins. A marine source rock, which was first identified as contributing to hydrocarbon generation in this region, probably plays a significant role in the deep- and ultra-deep water basins south to the Pearl River Mouth and Qingdongnan basins. The shelf margin delta depositional systems in the Baiyun Sag, sourced from the Pearl River, are currently primary exploration targets in the deepwater part of the Pearl River Mouth Basin, whereas the western Red River deltaic-submarine fan depositional systems, initially proven by drilling, are the possible major exploration reservoirs in the Qingdongnan deepwater areas. Current deepwater exploration targets at the large-sized structural traps and deep and ultra-deep areas in the south of the Pearl River Mouth and Qingdongnan basins will be the future exploration focus. Deepwater exploration activities and relevant fundamental studies, supporting and promoting each other, are of great importance to the national energy supply of China, the basic regional studies of the South China Sea, advancements in technology, and development of related deepwater industries, and will safeguard national sovereignty and territorial integrity.

Recognition and depiction of special geologic bodies of Member 3 of Dongying Formation in Littoral Slope Zone, Qikou Sag

The purpose of this study is to forecast the profitable oil and gas reservoir, which is the key of finding hydrocarbon, based on the conception of special geologic bodies. With the guiding methodology of the research thinking of integration of point-line-surface by using the methods and techniques of logging, seismic, seismic attribute, and logging constrained inversion in 3D data volume, the special geologic bodies of Member 3 of Dongying Formation in Littoral Slope Zone of Qikou Sag, which has important hydrocarbon exploration potential, are recognized and described under the constraint of sequence stratigraphic framework. As a result, the developed scale, geometric shape and space distribution feature of the special geologic bodies are forecasted; the inner structure and sequence structure patterns of the geologic bodies are also ascertained. From the lowstand system tract (LST) and lacustrine expanding system tract (EST) to the highstand system tract (HST), the geologic bodies have evolved from relative centralization of lake basin reducing period to three relative dispersive isolated parts of broad lake basin period. According to the relevance and regularity of the development of geologic bodies, the conclusions can be obtained that three types of potential profitable reservoir traps, including the lithologic lens traps, lithologic updip pinchout traps and structural-lithologic composite traps, are forecasted. In addition, scientific basis for further hydrocarbon exploration in new area (few-well area and no-well area) is offered in the guidance of sequence stratigraphic model.

Diagenesis of Paleozoic playa-lake and ephemeral-stream deposits from the Pimenta Bueno Formation, Siluro–Devonian (?) of the Parecis Basin, central Brazil

The Parecis Basin is a large intracratonic rift located in central Brazil and filled with Paleozoic carbonate, evaporite and siliciclastic sediments. The occurrence of gas seeps has recently attracted significant exploration interest by the Brazilian petroleum agency and by Petrobras. The continuously cored PB-01-RO well provided the first opportunity to study the depositional environments, diagenetic evolution and hydrocarbon potential of the largely unknown sedimentary successions of the Parecis Basin. The cored lithologies, belonging to the Siluro–Devonian (?) Pimenta Bueno Formation, are interpreted as deposited in playa-lake and ephemeral-stream environments. The deposits display a strong facies control on the diagenetic mineral assemblages and evolution. Diagenetic minerals in the ephemeral-stream deposits include eogenetic hematite and smectitic clay coats and quartz cement, and the mesogenetic process includes precipitation of sulfates (anhydrite and barite) and carbonates (calcite, dolomite and kutnahorite–ankerite–huntite), followed by partial dissolution of these carbonates and sulfates, and of feldspar grains. Telogenetic processes include the precipitation of hematite and kaolinite within secondary pores, and the replacement of anhydrite by gypsum. A second burial phase and mesodiagenesis is indicated by the precipitation of discrete K-feldspar crystals within moldic pores after dissolved feldspars, and by the illitization of etched, telogenetic kaolinite. The playa-lake deposits show early diagenetic dolomitization of lime mud, precipitation of anhydrite nodules and extensive silicification. The anhydrite nodules were replaced by gypsum and chalcedony during telodiagenesis. Potential source rocks are locally represented by organic shales. The fluvial sandstones show fair reservoir quality and limited compaction, as indicated by their intergranular volume, suggesting that the succession has undergone moderate burial. Potential seals for hydrocarbon accumulations are provided by the evaporites and playa-lake mudstones. The presence of an active petroleum system in the basin, as indicated by the gas seeps, suggests a good hydrocarbon exploration potential for the Parecis Basin, gas and stresses the importance of studying the depositional and diagenetic evolution of its sedimentary successions.

Impact on hydrocarbon exploration potential of a structural study of the Chott El Jerid area, Tunisia

Ghassen Chaari, Al Thani Emirates Petroleum, and Paul Tremolieres, retired professor, Institut Francais du Petrole, describe a structural study of the Tunisian Tozeur Block to identify the most prospective areas for future seismic and drilling activity.

Can stratigraphic plays change the petroleum exploration outlook of the Netherlands?

Abstract Fifty years after the discovery of the giant Groningen gas field, good insight into the remaining hydrocarbon exploration potential of the Netherlands is of great interest due to the aging infrastructure. In a review of prospective areas, the stratigraphic element of Dutch play areas has been summarized for conventional and unconventional formations. This is to answer the question of whether stratigraphic traps can contribute to future exploration. Complex faulting, very common in the Dutch subsurface, makes structural definition generally the highest prospect risk. With increase in 3D coverage over the country, many structures have now been drilled successfully. The success of structural traps has left the stratigraphic plays and prospects under-explored. Most hydrocarbon reserves in the Netherlands have been discovered in Permian Rotliegend and Triassic Bunter sandstone reservoirs, which are not prone to much stratigraphic trapping as a consequence of very gradual facies changes. Other prospective horizons and hydrocarbon reservoirs in the country range in age from Carboniferous to Cenozoic and can be found in clastic and carbonate rocks. They share an overall comparable basin setting but the varying interplay at basin margins creates varying stratigraphic elements. Rifting creates new facies variation during the Mesozoic. Salt movement is another factor that creates stratigraphic components in trapping. The various erosional events create other possibilities for stratigraphic trapping. This, combined with varying relative sea-levels through time, creates very distinct stratigraphic intervals often correlatable over large distances. The very limited contribution of stratigraphic traps to present-day gas finds may change in the future because of improved seismic. Risking of prospects needs better understanding of stratigraphic elements in various plays. This includes the stratigraphic aspects of reservoir sealing in dominantly structural traps and the nature of source horizons.

Comparative petroleum systems analysis of the interior basins of Turkey: Implications for petroleum potential

The interior basins of Turkey remain effectively unexplored and their petroleum systems are poorly understood. This paper presents a comparative summary of the geological evolution, petroleum potential and prospectivity of the Central (Tuz Gölü, Sivas and Çankırı) and East Anatolian (Muş-Hınıs, Pasinler-Horasan and Tercan-Aşkale) basins using geological, seismic, geochemical and petrophysical data, and a series of quantitative basin models. The studied basins are ranked on the basis of source effectiveness, reservoir quality, seal efficiency, and the timing of hydrocarbon expulsion and migration relative to trap formation. A qualitative risk assessment, based on the elements of the petroleum system, is used to evaluate the likelihood of hydrocarbon discovery in each of the basins. This study shows that the chance of hydrocarbon discovery in the East Anatolian basins is unlikely-very unlikely and Tuz Gölü, Sivas and Çankırı basins are equally likely/unlikely-unlikely, likely and unlikely, respectively. Heavy oil and minor gas associated with two mature petroleum systems were discovered in the Tuz Gölü basin. Various trap forming mechanisms such as salt tectonics and Middle Eocene compression, accompanied by the effective sealing capacity of the Eocene evaporites favor the hydrocarbon exploration potential of the Tuz Gölü basin. The highest exploration risk in the Tuz Gölü basin arises from the poor quality sandstone reservoirs. The biggest risk factor in the Eastern Anatolian basins is insufficient thermal maturity, despite the presence of good quality source rocks. The Sivas basin is one of the most promising interior basins of Turkey due to the presence of multiple mature petroleum systems and high quality reservoirs. There is a high chance of accumulation of multi-phase hydrocarbons in the Eocene and Miocene traps. The major problem in the Sivas basin is the lack of an efficient seal rock. The Çankırı basin contains all of the necessary elements of an ideal petroleum system except the presence of an organic-rich source rock. Thus, the chance of hydrocarbon discovery in the Çankırı basin is low.

Hydrocarbon generation conditions and exploration potential of the Taoudeni Basin, Mauritania

The Taoudeni Basin is a typical and steady intracratonic basin in Mauritania, northwest Africa. There are six sets of potential source rocks and five regional unconformable surfaces of the Infracambrian and Paleozoic developed in the basin. We used seismic stratigraphic correlation to recover the denudation thickness of formations at a particular well location. Studies of the hydrocarbon generation history of the basin illustrate that hydrocarbon migration and accumulation occurred in the end of the Carboniferous, and after that, the whole basin suffered denudation for a long period of time. Because there is no thick Mesozoic overburden in the basin, the Silurian source rocks could not generate hydrocarbon in the Mesozoic era for the second time. Consequently, the prospects for successful hydrocarbon exploration in the basin are not good.