Petroleum Play Research Articles

The impact of exploration/appraisal activities on the recovery per well in North Perth Basin

The North Perth Basin (NPB) in Western Australia has experienced significant petroleum industry activity over the past 3 years (2021–2023), marked by the drilling of exploration and appraisal wells by various operators, along with notable merger and acquisition transactions. This flurry of drilling activity, coupled with the acquisition of new seismic data, have enhanced our understanding of the variability within the primary petroleum play levels – namely, the Permian ‘Kingia’ and High Cliff reservoirs. This understanding is crucial for assessing the future potential of domestic gas supply in Western Australia. This paper aims to elucidate how recent drilling efforts have narrowed the basin-wide portfolio of available gas prospects relative to the situation in early 2021, and how the landscape of undiscovered gas resources has evolved. This shift is attributed to both unsuccessful exploration attempts and revised estimates of well deliverability. Furthermore, an updated long-term production forecast for the NPB – considering existing gas pools and the newly assessed undiscovered resources – emphasises the urgent need to re-evaluate the narrative concerning gas availability for the domestic market. The Permian gas plays within the NPB have proven to be more intricate and unpredictable than previously believed. Nonetheless, their significance to the Western Australian economy is anticipated to be substantial for many years ahead.

U–Pb zircon ages, mapping, and biostratigraphy of the Payette Formation and Idaho Group north of the western Snake River Plain, Idaho: Implications for hydrocarbon system correlation

ABSTRACT Sedimentary deposits north of the western Snake River Plain host Idaho’s first and only producing oil and gas field. They consist of the lower to middle Miocene Payette Formation, the middle to upper Miocene Poison Creek and Chalk Hills Formations, and the Pliocene to lower Pleistocene Glenns Ferry Formation. Using new geochronology, palynomorph biostratigraphy, and geologic mapping, we connect updip surface features to subsurface petroleum play elements. The Payette Formation is a likely main source of the hydrocarbons, and acts as one of the reservoirs in the unnamed basin. Here, we redefine the Payette Formation as 0 to ~3,500 ft (0 to ~1,000 m) of mudstone, with lesser amounts of sandstone overlying and interbedded with the Columbia River Basalt Group and Weiser volcanic field. Index palynomorphs, including Liquidambar and Pterocarya, present in Idaho during and immediately after the middle Miocene climatic optimum, and new U–Pb ages of 16.39 and 15.88 Ma, help establish the thickness and extent of the formation. For the first time, these biostratigraphic markers have been defined for the oil and gas wells. The Poison Creek Formation is sandstone interbedded with mudstone that is ~800–1,800 ft (250–550 m) thick. The Chalk Hills Formation is a tuffaceous siltstone, claystone, and sandstone that is as much as ~4,200 ft (1,280 m) thick. New U–Pb ages are 10.1, 9.04, and 9.00 for the Poison Creek Formation, along with maximum depositional ages of 10.7 to 9.9 Ma for four samples from the Poison Creek Formation. A single U–Pb age of 7.78 Ma was determined from pumice low in the Chalk Hills Formation. Like the Payette Formation, the Poison Creek Formation can be a reservoir, whereas the Chalk Hills Formation acts as a sealing mudstone facies. The overlying sandstone, siltstone, and conglomerate of the Glenns Ferry Formation act as the overburden to the petroleum system in the subsurface, and were important for burial and hydrocarbon maturation. The Glenns Ferry Formation is up to 500 ft (150 m) thick in the study area, as much has been eroded. Whereas the Payette and Poison Creek Formations were deposited during the mid-Miocene climatic optimum amongst and above volcanic flows, the Chalk Hills and Glenns Ferry Formations were deposited within ancient Lake Idaho during an overall increase in aridity and cooling after the mid-Miocene climatic optimum.

Static Reservoir Simulations and Seismic Attributes Application to Image the Miocene Deep-Water Reservoirs in Southeast Asia

Globally, deep-water reservoir systems are comprised of a variety of traps. Lateral and downdip trapping features include sand pinch-outs, truncation against salt or shale diapirs, and monoclinal dip or faulting with any combination of trapping designs; the potential for massive hydrocarbon accumulations exists, representing significant exploration prospects across the planet. However, deep-water turbidites and submarine fans are two different types of traps, which are developed along the upslope and the basin floor fans. Among these two traps, the basin floor fans are the most prolific traps as they are not influenced by sea-level rise, which distorts the seismic signals, and hence provides ambiguous seismic signatures to predict them as hydrocarbon-bearing zones for future explorations. Therefore, the deep-water channel-levee sand systems and basin floor fans sandstone define economically viable stratigraphic plays. The subsurface variability is significant, and hence, characterizing the thick (porous) channelized-basin floor fans reservoir is a challenge for the exploitation of hydrocarbons. This study aims to develop seismic-based attributes and wedge modeling tools to accurately resolve and characterize the porous and gas-bearing reservoirs using high-resolution seismic-based profiles, in SW Pakistan. The reflection strength slices better delineate the geomorphology of sand-filled channelized-basin floor fans as compared to the instant frequency magnitudes. This stratigraphic prospect has an area of 1180 km2. The sweetness magnitudes predict the thickness of channelized-basin floor fans as 33 m, faults, and porous lithofacies that complete a vital petroleum system. The wedge modeling also acts as a direct hydrocarbon indicator (DHI) and, hence, should be incorporated into conventional stratigraphic exploration schemes for de-risking stratigraphic prospects. The wedge model resolves a 26-m thick hydrocarbon-bearing channelized-basin floor fans lens with a lateral distribution of ~64 km. Therefore, this wedge model provides ~75% correlation of the thickness of the LSL as measured by sweetness magnitudes. The thickness of shale that serves as the top seal is 930 m, the lateral mud-filled canyons are 1190 m, and the thick bottom seal is ~10 m, which provides evidence for the presence of a vibrant petroleum play. Hence, their reveals bright opportunities to exploit the economically vibrant stratigraphic scheme inside the OIB and other similar global depositional systems.

Geochemical characteristics of inclusion oils and charge history in the Fushan Sag, Beibuwan Basin, South China Sea

The Fluid Inclusion (FI) petrology and biomarker analysis of the inclusion oils were carried out on three sandstone samples from the Liushagang Formation (Els) reservoirs in the Fushan Sag, the Beibuwan Basin, South China Sea. The purpose of this study is to identify the origin of the inclusion oils and understand the charging history and oil accumulation process in the Els reservoirs through the inclusion oil-source correlation, analysis of Homogenization Temperature (Th) and 1D basin modelling. The results show that the maturities of the Els22 inclusion oils are higher than that of the Els1 inclusion oil based on methylphenanthrene index and the inclusion oils were originated from fluvial/delta mudstone. The geochemical correlation between the inclusion oils and source rocks based on the biomarkers clearly shows that the inclusion oils from the Els22 sandstone reservoirs may have sourced from Els22 source rock or mixed source from the Els3 and Els22 mudstones, and the inclusion oil in the Els1 reservoir was generated from the Els1 source rock in the sag. The oil source of inclusion oils from different layers was almost consistent with that of crude oil in reservoirs. Combined with the Th of the FIs and 1D basin modelling, two episodes of oil charge are identified in the center of the Bailian Sub-sag: the first oil charge in the Els22 reservoirs started around 38.5 Ma in the lower petroleum play, which is consistent with the early oil generation time of the Els3 and Els22 source rocks in the Bailian Sub-sag. The second oil charge in the Els1 reservoir was coincided with the early oil generation time (∼13-0 Ma) of Els1 source rock. The oil charge and accumulation occurred in the isolated upper and lower petroleum plays. The oil charge and accumulation in the lower petroleum play from the Els3 and/or Els22 source rocks is almost distributed in the whole sag, and the oil in the upper petroleum play from the Els21 and/or Els1 source rock is mostly distributed in the center of the sag.

Petroleum play types and source rocks in the Pannonian basin, insight from the Slovak part of the Danube Basin

The Danube Basin represents a Miocene depocenter located on the NW margin of the Alpine-Pannonian-Carpathian region and is considered a partial sub-basin of the larger Pannonian Basin System. The gradual opening of the northern Slovak part of the basin during a 4-stage rifting event between the Badenian, Sarmatian (Langhian, Serravallian) to Pannonian (Tortonian) time reflected not only on the sedimentary fill and the development of volcanic fields but also on individual elements of the petroleum system. The presence of effective petroleum systems is supported by several gas and condensate deposits together with abundant hydrocarbon shows. The study offers new insight into the petroleum plays in Danube Basin based on new and vintage reflection seismic lines and organic geochemistry data. The novel findings reveal that within the older sub-basins (Blatné and Želiezovce) the main source rock is the lower Badenian mudstone with mixed Type III/II kerogen. Paleogene shales with Type II kerogen together with Pre-Cenozoic basement Type III/II rocks cannot be excluded. In the younger sub-basins (Komjatice and Gabčíkovo-Győr) the main source rocks are upper Badenian – Sarmatian, and Pannonian mudstones with Type III/II kerogen. Two gas play groups are defined. 1) Plays in older sub-basins characterized by structural traps mostly in the Badenian reservoirs. 2) Plays in younger sub-basins characterized by stratigraphic and structural traps in Sarmatian and Pannonian reservoirs. Non-hydrocarbon gas risk arises from CO2 and N2 contents sourced from buried volcanic fields. The volume of inert gasses trapped in particular sub-basins is dependent on the timing and type of volcanism. It is lower in the older sub-basins and higher in the younger ones, at the same time, the risk is lower in stratigraphically highest reservoir intervals.

Seismic Characterization to Identify Geological Structures and Petroleum Play in Lower Indus Basin, Pakistan

The Cretaceous shale intervals of Talhar and Sembar Formations – distributed in the Lower Indus Basin of Pakistan – are organic-rich shales that can act as shale gas plays. Two-dimensional seismic using synthetic modeling has been carried out in Khewari oil field to identify petroleum plays. This work was completed with the help of eight seismic processed and migrated lines. Based on structural interpretation different geological structures were marked. The seismic character, continuity, and coherency in seismic reflection patterns indicate that the area is under an extensional regime with normal faults pattern associated with horst and graben structure. This structure is favorable for the accumulation of hydrocarbon. The shales of Talhar and Sembar formations are overlying Chilton limestone, which is a proven reservoir. The isopach maps show that Talhar Shales and Sembar Formation are dipping towards the northeast. Precisely to characterize the reflector, a synthetic seismogram was employed to tie well tops and seismic profiles.

Petrophysical Evaluation of H-field, Niger Delta Basin for Petroleum Plays and Prospects

Abstract in English As a result of a combination of several methodologies, the H-Field, Niger-Delta, has been delineated. To identify probable reservoirs, seals, and source rocks in the study area, this study integrates sequence stratigraphy with petrophysical concepts through a comprehensive analysis of 3D seismic and well logging datasets. According to the 3D facies model, reservoirs are dominated by sand and are laterally extensive. They were then upscaled and stochastically distributed to create a 3D reservoir property model. On average, the porosity of these clastic reservoirs ranges from 22 to 28%. Reservoir net-to-gross (NTG) ratios range from 0.67 to 0.96. Water saturation ranges from 8% to 30%, while hydrocarbon saturation ranges from 70% to 92%. Four gas-bearing units and six oil-bearing units are present in reservoirs P 0.5 and P 1 compartments. All reservoir intervals’ oil and gas volumes are evaluated based on the hydrocarbon distribution. Geological models of the subsurface, such as the one in this paper, are crucial for future reservoir development programs.

The Carboniferous low stand complex: a new conceptual petroleum play in the Kosyu-Rogov Foredeep, the Timan-Pechora Basin

The Carboniferous low stand complex: a new conceptual petroleum play in the Kosyu-Rogov Foredeep, the Timan-Pechora Basin

Hydrocarbon Tracers Suggest Methane Emissions from Fossil Sources Occur Predominately Before Gas Processing and That Petroleum Plays Are a Significant Source.

We use global airborne observations of propane (C3H8) and ethane (C2H6) from the Atmospheric Tomography (ATom) and HIAPER Pole-to-Pole Observations (HIPPO), as well as U.S.-based aircraft and tower observations by NOAA and from the NCAR FRAPPE campaign as tracers for emissions from oil and gas operations. To simulate global mole fraction fields for these gases, we update the default emissions’ configuration of C3H8 used by the global chemical transport model, GEOS-Chem v13.0.0, using a scaled C2H6 spatial proxy. With the updated emissions, simulations of both C3H8 and C2H6 using GEOS-Chem are in reasonable agreement with ATom and HIPPO observations, though the updated emission fields underestimate C3H8 accumulation in the arctic wintertime, pointing to additional sources of this gas in the high latitudes (e.g., Europe). Using a Bayesian hierarchical model, we estimate global emissions of C2H6 and C3H8 from fossil fuel production in 2016–2018 to be 13.3 ± 0.7 (95% CI) and 14.7 ± 0.8 (95% CI) Tg/year, respectively. We calculate bottom-up hydrocarbon emission ratios using basin composition measurements weighted by gas production and find their magnitude is higher than expected and is similar to ratios informed by our revised alkane emissions. This suggests that emissions are dominated by pre-processing activities in oil-producing basins.

Sequence stratigraphic framework of ‘AKOS’ field, Niger Delta

The aim of this study is to investigate the sequence-stratigraphic framework of a hydrocarbon prospect of ‘AKOS’ Field, Niger Delta, using well logs, and 3-D seismic data. To achieve this, the researchers identify the various sand/shale and seismic facies, build a sequencestratigraphic framework of the oilfield, and assess the petroleum play of identified system tracts. A fault analysis reveal twelve (12) fault sets (Fault 1-12) mapped across the seismic volume. These faults are picked on an increment of 50 and examined for consistency using time slice and variance attributes. Faults-1 and 2 are major faults. The other ten (10) are minor faults. The mapped faults are normal growth faults common in the Niger Delta, as most trend approximately E-W direction. Sequence-stratigraphic analysis of the prospect based on chronostratigraphic correlation reveal two (2) sequences. Sequence-1 is between Sequence Boundary (SB) 0 to SB-1. Sequence-2 is between SB-1 to SB-2. Results from interpreted and analyzed system tracts reveal all three (3) present in Sequence-1. However, the Lowstand System Tract (LST) is absent in Sequence-2. The Lowstand Systems Tracts (LST) identified by shallowing and coarsening-upward succession, and progradational and aggradational parasequence sets are major hydrocarbon-producing intervals within the oilfield. The Transgressive Systems Tract (TST) typified by dirtying-upward seal the Lowstand Reservoirs. The upper section of the Highstand Systems Tracts (HST) has reservoir potential.

Fault Mesh Petroleum Plays in the Donghetang Area, Tabei Uplift, Tarim Basin, Northwestern China, and Its Significance for Hydrocarbon Exploration

Abstract —The hydrocarbon formation mechanism and potential targets in clastic strata from the Tabei Uplift, Tarim Basin, are documented using the fault mesh petroleum plays theory, based on integrating seismic, well log, well core, and geochemical data. The reservoirs in the Donghetang area are typical allochthonous and far-source fault mesh petroleum plays. There are two sets of fault meshes in the study area: (1) the combination of the Donghe sandstone and Permian–Triassic strata and (2) the combination of the fourth and third formations in the Jurassic strata. The fault mesh petroleum play in the Jurassic is a secondary reservoir that originates from the Carboniferous Donghe sandstone reservoir adjustment based on source correlation. The fault mesh carrier systems show the fully connected, fault–unconformity–transient storage relay, fault–transient storage–unconformity relay, and transient storage–fault relay styles, according to the architecture of the fault mesh. Based on the characteristics of the fault mesh petroleum plays, the reservoirs are divided into three categories (upper-, inner-, and margin-transient storage styles) and 15 styles. Integrated analysis of the hydrocarbon generation and faulting time periods reveals that there were four periods of hydrocarbon charging, with the first three stages charging the reservoirs with oil and the last stage charging the reservoirs with gas. There are multiple stages of reservoir accumulation and adjustment in the fault mesh in the study area. These stages of fault mesh accumulation and adjustment are the main reason why the reservoir distribution multiple vertical units have different hydrocarbon properties. Fault-block and lithologic reservoirs related to the inner- and upper-transient storage styles are the main exploration targets in the clastic strata in the study area.

Thermo‐tectonic history of the Northeast Sichuan Basin, Southwest China, using apatite fission‐track analysis, vitrinite reflectance, and basin modelling: Implications for hydrocarbon prospectivity

Analysis of apatite fission‐track and vitrinite reflectance combined with 1‐D basin modelling was used to reconstruct the thermo‐tectonic history of the northeast Sichuan Basin, China. The study indicates that the basin has evolved through multi‐phase tectonic regimes involving a series of subsidence and tectonic uplift phases exerting significant control on the thermal history. Heating and cooling processes were largely related to deep burial and intense exhumation, respectively. Exhumation that extended from 122 to 2.5 Ma has resulted in at least 4 km of sedimentary removal. The rate of exhumation and removal (denudation) was found to have reached 58 and 35 m/Myr, respectively. The results show that the denudation magnitude is significantly higher in the eastern part reaching 5.5 km, compared with 2.2 km in the western part of the study area. The fission‐track ages demonstrate the occurrence of three cooling phases: initial‐gradually increasing (~120–70 Ma), stagnant (70–15 Ma), and rapid (15 Ma to present). This suggests that cooling was associated with different compressive thermo‐structural events that began in the mid‐Lower Cretaceous (~122 Ma) marking the subsidence climax period. With the sedimentary section approximating 8‐km thickness by the time of maximum burial, the modelled average maximum temperature and vitrinite reflectivity coefficient reached roughly 232°C, and 3.5% for the Lower Triassic Feixianguan Formation (T1f1), thus indicating the conditions of dry gas generation. The Meso‐Cenozoic thermo‐structural evolution that postdated the onset of hydrocarbon generation has been critical for the evolution of the petroleum play, including the Feixianguan Formation in the marine carbonates of the Early Triassic and the Xujiahe Formation in the non‐marine sandstones of the Upper Triassic. This resulted in the modification of primary hydrocarbon accumulations, mostly in the lower petroleum play, and development of secondary accumulation in the newly formed structural traps in the upper petroleum play. Therefore, accurate thermo‐tectonic history reconstruction is valuable for understanding the geological history and hydrocarbon prospectivity.

Petroleum play of the Lower Cretaceous Alam El Bueib Formation in the El Noor-1X well in the north Western Desert (Egypt): A sequence stratigraphic framework

Abstract The North Umbaraka concession in Umbaraka Basin in the northern the Western Desert of Egypt has been the subject of continuous exploration efforts in the recent years. Despite many oil discoveries gave evidence of a working petroleum system, however, there is little economic production. The petroleum plays of the Alam El Bueib Formation are in the central focus of the exploration in this region because of their high economic reservoir potentiality in other areas of the Western Desert. In the present study, three powerful tools are used to delineate the sequence stratigraphic frame that considers the occurrences of the petroleum play chances of Alam EL Bueib Formation in El Noor-1 well. These tools are palynofacies, electric log and organic geochemistry. The palynofacies analysis revealed three biotopes that cover deposition in wave dominated to fluvial-wave dominated deltas with energetic, oxic and active reworking conditions. These environmental settings are only suitable for deposition of organic-lean hydrocarbon source. However, there are abundant organic materials that fluoresce under the UV-V-blue incident light especially in Proximal Delta Front/Prodelta Slope biotope (A) and these materials can generate oil as indicated also by pyrolysis gas chromatography. In addition, analysis of electric logs is used to assess reservoir capacities and effective porosities in the studied rocks. Eight sequences are identified based on these trends including E4, E3, E2, E1, D1, C1, C2 and B1. Four petroleum plays are determined in the studied succession within the frame of the stratigraphic sequences E, D, C and B. There are six reservoirs identified in the sandy bodies of the lowstand systems tracts and the carbonates of the transgressive and highstand systems tracts. The critical moment of hydrocarbon generation occurred during the Campanian (76 Ma). The entire succession of the Alam El Bueib Formation is in the oil window and the source rocks in this formation initiated petroleum expulsion during the Eocene time (32 Myr).

ПЕРСПЕКТИВЫ НЕФТЕГАЗОНОСНОСТИ И ОСВОЕНИЯ УГЛЕВОДОРОДНОГО СЫРЬЯ ХАТАНГСКО-ОЛЕНЕКСКОГО МЕЖДУРЕЧЬЯ

Based on the integration of results of archival and modern seismic surveys, well logging data and results of analytical studies of core material, the structure of the Permian prospective petroleum play (PPPP) in the north-eastern framing of the Siberian Platform was clarified. In accordance with the author’s algorithmic approach, the map of minimum economic sizes of discoveries was constructed. This map takes into account predicted characteristics of reservoirs and the probable structural complexity of geological features.

Style and timing of salt movement in the Persian Gulf basin, offshore Iran: Insights from halokinetic sequences adjacent to the Tonb-e-Bozorg salt diapir

The variations in the rate of salt rise is reflected in the sedimentary sequences adjacent to salt diapirs and provides insights into the style of salt movement-sedimentation interaction and the timing of halokinetic phases. Episodic movement of salt diapir is defined by wedge- and tabular-shaped salt-related sedimentary strata (halokinetic sequences) adjacent to the diapir. Detailed mapping of depositional strata on 2D seismic sections adjacent to salt diapirs on the Tonb-e-Bozorg Island (Persian Gulf, SW Iran) reveals the presence of a series of sedimentary sequences related to the halokinetic activity of two salt source layers, the Hormuz and Fars salts, respectively. The Hormuz salt deposited in the uppermost Proterozoic, mobilized in the Lower Paleozoic and then continued to move periodically to present and to create the deep salt structures in the Tonb-e-Bozorg region. The Fars salt deposited in the Lower Miocene and then started rising, and created the central salt structure, the Tonb-e-Bozorg Island, and several peripheral ring-like salt structures around the island. Our results reveal that both the salt layers within the Tonb-e-Bozorg region grew by downbuilding and continued to move periodically by passive and active diapirism to the present. Salt movement-sedimentation interaction during salt diapirism influences petroleum play and therefore is of interest in petroleum geoscience.

Petroleum Plays of the Bowen and Surat basins

The plays of the Bowen and Surat basins consist of conventional structural plays along major regional structures and depositional platforms, most of which have some stratigraphic component. These can be subdivided into three main regions: the eastern and western flanks of the Taroom Trough, and the Denison Trough. Coal seam gas is found in fairway zones within the Permian coals of the Bowen Basin, which can be subdivided into two main fairways: structurally associated plays in the southern Bowen Basin, and a tighter play in the northern Bowen Basin. Coal seam gas is also found along a broad fairway in the Walloon Coal Measures of the Surat Basin. Recent exploration for new targets has highlighted potential for tight gas in the deeper sections of the Bowen Basin, though further evaluation is required. More speculative plays within the region include tight gas within potential, but untested targets in the deeper sections of the Denison Trough.

Oil and gas reservoirs of weathering crusts and Paleozoic basement in the southeast of Western Siberia (forecasting of hard-to-recover reserves)

The study and development of hard-to-recover reserves in the pre-Jurassic petroleum of Western Siberia is a new focus for development of the resource base and oil production in Russia, identified the necessity of assessing a special strategy, a conceptual scheme for forecasting and exploration. The aim of the study is to identify and assess the primary research areas of hydrocarbon reservoirs in pre-Jurassic basement by the example of underexplored areas of the Ust-Tym mega-depression and structures of the Nurol’ka mega-depression which are located on the well-developed oilfield infrastructure areas of Tomsk region. Object of study is the potential pre-Jurassic reservoirs of Permo-Triassic weathering crust and Paleozoic basement. The accumulations of weathering crust are associated with reservoirs formed on clay and siliceous, carbonate and acid volcanic rocks, and, under certain conditions, by ultrabasites. The reservoirs of bedrock are associated with secondary reservoirs formed by limestones, granites, rhyolites. The main oil source formation is the Lower-Jurassic Togur sediments. The study is carried out based on the concept of mainly vertical hydrocarbon migration. The research area is located in boundaries of the oil source formation. Thermal history reconstruction of oil source formation, cumulatively taking into account the temperatures of the localized source kitchen, is carried out by solving the direct and inverse problems of geothermy. The studies are based on a special technology that includes an integrated analysis of mapping results of the Togur oil source kitchen by the geotemperature criterion and predicting mapping of the weathering crust and the Paleozoic basement reservoirs according to the data of deep drilling, oil geological zoning and perspective areas ranking. In the territory of the Ust-Tym megadepression as the primary research area for the weathering crust reservoir the zone of the northeastern side of the megadepression has been selected. As the priority area for exploration of Paleozoic basement reservoirs the zone uniting the north-eastern slope of North-Parabel megamonocline and the adjacent southern part of Pyzhinsk mesodepression has been selected. As the perspective research area for the weathering crust reservoir the land of the south beads of Kulan-Igay and Tamrad basins and its adjacent areas for the territory of Nurol’ka megadepression have been identified. As the priority areas for research and development of Paleozoic basement reservoirs the south beads of Kulan-Igay basin and adjacent zone of Tamrad basin have been identified, as well as the lands of the south-eastern beads of Nurol’ka megadepression and the adjacent lands of Chuzik-Chizhap mesosaddle. The reliability of the forecast for perspective areas of the pre-Jurassic petroleum play is identified by comparison with the results of well testing and is about 70—80 %. It argues the previously formulated resource-efficient strategy and technology of exploration for oil deposits in the pre-Jurassic basement of Western Siberia.

Triassic petroleum system as an alternative exploration concept in offshore western Timor Indonesia

Located in the north-western part of Bonaparte Basin, offshore western Timor presents the opportunity for a distinct exploration concept due to the discovery of the Abadi gas field. A classic Jurassic petroleum play did not develop as a proven reservoir and source rock in the study area due to severe erosion during the Valanginian event. Therefore, the Triassic interval requires assessment to reveal an alternative petroleum system in the study area. A petroleum system analysis utilising 2D seismic lines and three exploration wells was performed to construct a new exploration concept. The study showed that the Scythian Mount Goodwin interval could be considered a primary gas-prone source rock, with type II/III kerogen, a total organic content up to 2.09% and a hydrogen index that could reach 569 mg/g. Based on a study of a pseudo-well conducted here, the Mount Goodwin interval is found to have reached gas generation in the Early Cretaceous and expulsion in the Early Eocene. The potential reservoir rocks are the Carnian–Ladinian Challis and Anisian Pollard intervals. The Challis interval, the primary reservoir, has typical shoreline sandstones and is interbedded with claystones and limestone intercalations. Petrophysical and petrographic studies in this interval indicate good reservoir properties. However, the Pollard interval mainly consists of carbonates with minor claystones and has a low quality of reservoir properties. The intraformational shale of the Challis is considered as the potential regional seal, especially within areas that are not truncated by the Valanginian event. From the perspective of exploration, the Jurassic north-east–south-west-tilted fault blocks are still favourable for new discoveries in the offshore western Timor area.

Seismic stratigraphy of Dinantian carbonates in the southern Netherlands and northern Belgium

AbstractDue to their potential as a petroleum or geothermal system, the Dinantian carbonates of the Netherlands have recently attracted renewed interest because of the identified presence of excellent reservoir properties. This notion contrasts with the general assumption that these carbonates are tight. Therefore, in order to give the current knowledge state, this paper re-examines the sparse publicly available well and seismic data and literature to assess the distribution and reservoir properties of the Dinantian carbonates.Dinantian carbonate deposition occurred throughout the study area (southern onshore and offshore of the Netherlands and northern Belgium), which is situated on the northern margin of the London–Brabant Massif, progressively onlapping the latter structure. This study confirms the presence of three carbonate facies types in the study area: a Tournaisian low-gradient carbonate ramp system, succeeded by a succession in which the carbonate ramp system evolved to a rimmed shelf setting. Subsidence of the northern margin of the London–Brabant Massif resulted in a landward shift of the shallow-marine facies belts, while the formation of normal faults resulted in a ‘staircase’-shaped shallow-water platform–slope–basin profile, associated with large-scale resedimentation processes. After deposition, the limestone deposits were frequently exhumed and reburied. A first period of regional exhumation occurred at the end of the Dinantian, which seems to be associated with porosity-enhancing meteoric karstification, possibly limited to the palaeo-shelf edge. The most intense alterations seem to be present as a deep leached horizon below the Cretaceous unconformity at the top of the Dinantian sequences. In addition, clear evidence for hydrothermal fluid migration is found locally, enhancing reservoir properties at some places while occluding porosity at others. The timing of these phases of hydrothermal fluid circulation is poorly understood.Whereas in the United Kingdom hydrocarbons have been produced from karstified Dinantian carbonates, this petroleum play has received little attention in the Netherlands. This paper shows that, also for the Netherlands, a karstic reservoir probably existed before the start of hydrocarbon generation from the onlapping basal Namurian shales. The hydrocarbon prospectivity of these sediments, however, is primarily controlled by the presence of both a karst-related reservoir and migration routes from a decent-quality source rock. Two geothermal projects producing from this reservoir in the southern onshore Netherlands have shown the potential of the Dinantian carbonates for ultra-deep geothermal projects. To conclude, the findings presented herein are relevant for studies of the hydrocarbon prospectivity and studies of the geothermal potential of Dinantian carbonates in the Dutch on- and offshore.

Statistical analysis as a tool for assisting geochemical interpretation of the Upper Triassic Yanchang Formation, Ordos Basin, Central China

The Yanchang Formation in the Ordos Basin is the most important petroleum play not only for conventional oil and gas accumulations, but also for newly emerging shale oil and tight gas resources. The molecular characterization of the basinwide source rocks predicts three groups of generative petroleum types: Paraffinic High Wax Oil, mixed base (Paraffinic-Naphthenic-Aromatic) Low Wax Oil, and Gas and Condensate. Supplementary to previous work, 68 samples including the crude oils, source bitumens and reservoir extracts from the Yanchang petroleum play are analyzed. The distribution of two terpane classes (eight tricyclic terpanes and eight pentacyclic terpanes) are determined with subsequent simultaneous RQ-mode factor analysis for a composite data set of these samples alongside 216 published crude oils worldwide with known facies descriptions. Thermal maturity has been evaluated as a consistent distribution at first using a combined method of a maturity-related biomarker [Ts / (Ts+Tm)] and aromatic parameters (Methyldibenzothiophene Ratios) to alleviate the maturity differences effect when discussing geochemical characterization. The R-mode factor analysis consists of the first two factors that are describing 45 present of the cumulative total variance in the data set, and presents a sample grouping pattern in Q-mode factor analysis which is determined by different contributions of terpane associations, i.e., the tricyclic C21 coupled with pentacyclic C26, C27, C28 and C30, in the same factor space. Three terpane associations, the C26 and C28 terpanes, the C21 and C30 terpanes and the C27 pentacyclic terpenes, are respectively responsible for discriminating crude oil, reservoir extracts and source bitumens in RQ-mode factor analysis. Molecular compositions further address more detailed interrelationships among three sample groups that crude oils and reservoir extracts are sharing close genetic relationships both in depositional environment typing and C27-C28-C29 sterane distribution. Samples from source rocks vary much significantly. A mixing process which occurs after oils has been expelled from host source rocks into carrier units during accumulation. In addition, the migration-contamination of C29 sterols when oils are cross through the Chang 7–2 unit along migration pathways might also explain this lack of correlation between source rocks and oil-reservoir system.