Journal of Petroleum Geology最新文献

Exploration efforts around the Greater Caucasus region started towards the end of the 19th century and established a wide range of petroleum play types in various basin segments around the orogen. All these plays are associated with the flanks of the inverted thrust-fold belt and the adjacent foreland basin systems, but display significant variation among the basin segments depending on the tectonostratigraphic units involved and the degree of exploration maturity. Whereas the same main source rocks have generated most of the hydrocarbons in all the basins (namely organic-rich shales in the Oligocene – Lower Miocene Maykop Group and the Eocene Kuma Formation), it is primarily the trapping style, both proven and speculative, which is responsible for the broad spectrum of play types observed. Eleven play type diagrams across six main petroleum provinces of the Greater Caucasus region are presented in this paper and summarize the current exploration understanding of the existing discoveries and potential new play targets. These play cartoons offer a prospect-scale summary of both mature producing and underexplored basin segments in a coherent visual manner, and are therefore intended to promote future exploration efforts in the Caucasus region. The testing of new play types requires the proper risking of the two most critical elements in the region: hydrocarbon kitchen effectiveness, and post-charge trap modification. The de-risking of these factors will require properly designed, fit-for-purpose acquisition of modern geological and geophysical data sets.

Nine Mesozoic and Cenozoic palaeogeographic maps are presented to illustrate the petroleum prospectivity of the South Caucasus from a fresh perspective and as part of the wider Caucasus region. Previously, elements of petroleum systems – reservoir, source and sealing lithologies, and the timing of their formation – have mostly been examined within individual sub-basins or licence blocks, and regional understanding has been limited. Emphasis is placed here on the onshore prospectivity of Georgia and Azerbaijan; the well-known Pliocene Productive Series of eastern Azerbaijan and the southern Caspian is not considered.

The Great Caucasus Basin (GCB) formed in the Early Jurassic following closure of PalaeoTethys, and remained a significant feature, despite structural modifications, until end-Eocene underthrusting and uplift converted the basin into the Greater Caucasus mountains. By the Toarcian a major delta system had developed along its northeastern margin, while the Transcaucasus block to the south was mostly covered by a shallow sea with limited sediment supply. Bajocian volcanism across the South Caucasus was accompanied by modification of the structure of the Great Caucasus Basin with the intrusion of tholeiitic dykes, possibly associated with onset of northward NeoTethyan subduction. Rising sea levels led to the abandonment of the GCB delta system. Relative uplift of the South Caucasus in the Bathonian created lowlands surrounded by marginal settings in which paralic deposits and coals were laid down. Jurassic hydrocarbon source rocks include deep-marine shales deposited within the Great Caucasus Basin together with coals; their potential is confirmed by numerous seeps within both Georgia and Azerbaijan. Various Middle Jurassic sandstones are potential reservoirs.

Carbonates dominated by the late Callovian, with widespread development of Oxfordian reefs and of Late Jurassic evaporite basins in the North Caucasus. Bedded anhydrites in Georgia comprise potential seals. Shallow-marine clastics again became widespread across the Caucasus in the Cretaceous, later replaced by carbonates including chalk-like limestones. Deeper-marine conditions persisted in the Great Caucasus Basin, which became less well-defined and split into separate depocentres. Fractured chalks are known reservoirs in the North Caucasus and prospective reservoirs in the South Caucasus.

Uplift of the southern South Caucasus during the Paleogene led to northward transport of sediment into evolving E-W to ESE-WSW basins in eastern Georgia and western Azerbaijan. Marine deposits within these basins form reservoirs, including thick fractured volcanogenic turbidites in eastern Georgia. Reduced sediment supply here at the start of the Late Eocene allowed organic-rich restricted-marine source rocks to accumulate.

Rapid uplift of the GCB associated with underthrusting at the end of the Eocene led to emergence of the Greater Caucasus mountains. The prolific Mai

Net erosion, the difference between the present-day and maximum burial depths of a reference unit, may have a major impact on hydrocarbon prospectivity in a sedimentary basin. Erosion may affect all the components of a petroleum system, from source rock to reservoir to seal. In most cases, vitrinite reflectance (VR), temperature and sonic velocity data, which are often readily available, can be used to determine net erosion in a region based on the thermal and mechanical evolution of sedimentary layers with burial. This paper revisits these methods and discusses the determination of net erosion from these datasets. Furthermore, it is shown that a closer look at the data is warranted if the estimates derived from complementary VR/temperature and velocity datasets significantly diverge. Such differences can be reconciled by critically examining the datasets and the regional geology, resulting in erosion estimates from both datasets which are within 100 m of each other. Lastly, a fully automated, process-driven method combined with multi-objective optimization algorithms and that takes all three datasets into account is showcased while determining net erosion for three wells located in the Norwegian Barents Sea. One of the benefits of this method is that it explores a wide range of likely scenarios that would best match the different datasets. Furthermore, the method can also automatically flag datasets that are inconsistent with each other by returning an overall low fit score. These datasets can then be critically examined to determine their reliability and to arrive at a more consistent erosion estimate, reducing the error margin to about 100 m.

Major oil discoveries have recently been made in Block T in the north of the Oriente Basin, Ecuador. The oil is reservoired in the M1 Sandstones of the Upper Cretaceous Napo Formation. To investigate the origin and charge history of the petroleum, a detailed geochemical study was carried out on 43 crude oil samples from 42 producing wells in Block T together with fluid inclusion analyses of three core samples from two wells.

According to the results of GC/GC-MS analyses of the oil samples, the oils contain n-alkanes with a peak carbon number at C₁₅-C₁₇ and a subordinate peak at C₂₅-C₃₀. The nC_21-/nC₂₂₊ ratio ranges from 0.64 to 1.69, and the Carbon Preference Index from 0.95 to 1.23. The odd-over-even predominance is 1.02–1.27. A cross-plot of C₂₂/C₂₁ versus C₂₄/C₂₃ tricyclic terpanes indicates that the source rock is a marine marl mixed with a small amount of terrigenous material. C₂₇ regular steranes are more dominant than C₂₈ ≈ C₂₉ and the C₂₉/C₂₇ ratio ranges from 0.67 to 0.94 indicating a source rock dominated by marine algal material with minor terrigenous input. R_c calculated using the MPI index was 0.83% to 1.11%, indicating that the oils were generated during the early to peak oil generation stage. A cross-plot of C₂₉ααα20S/(20S+20R) versus C₂₉αββ/(ββ+αα), and ratios of C₃₁L-hopane 22S/(22S + 22R) and C₃₂L-hopane 22S/(22S + 22R), gave similar maturity results.

The presence in the same oil samples of a complete n-alkane series together with an unresolved UCM hump and 25-norhopanes indicates at least two stages of oil charging, with severe biodegradation of the early-stage oil and a later charge of fresh, unaltered oil.

The homogenization temperatures of 36 fluid inclusions in samples from Block T wells F20 and F67 range from 81 to 95°C. A reconstructed burial and geothermal history of well F20 indicates that the M1 Sandstones in this area reached a temperature of 81°C at 19–16 Ma, after which temperatures increased continuously to 95–100°C at the present day. The homogenization temperatures of the analysed fluid inclusions combined with the geothermal history indicate that oil charging into the M1Sandstones began in the early Miocene and continues at the present day.

A 3D numerical modelling workflow was applied to the Barremian—Aptian source rock interval in a shelfal to lower slope area of the northern Orange Basin, offshore western South Africa. The main objective was to investigate the timing of hydrocarbon generation and migration. Hydrocarbon migration has previously been investigated in the south of the basin by relating gas escape features with structural elements as seen on seismic sections, but migration pathways are still poorly understood. The modelling study was based on data from three exploration wells (AO-1, AE-1 and AF-1) together with 42 2D seismic sections totalling 3537 km in length, and a 3D seismic cube covering an area of 750 sq. km.

Modelled formation temperatures increase from north to south in the study area and were consistent with downhole temperatures at well locations. However, there is variation between measured and modelled values of vitrinite reflectance (VR), especially in the Turonian and Cenomanian intervals. The measured VR is lower than the modelled VR within the Turonian section in the north of the study area, suggesting that erosion has affected the thermal maturity of the sediments. However, in the Cenomanian interval, the measured VR is higher than the modelled VR. Uplift, increased erosion in the hinterland and sediment transport to the coastal areas resulted in Cenomanian progradation of the Orange Basin fill. This together with a heat flow pulse resulted in increased thermal maturities in the study area.

Modelling results show that hydrocarbon generation began in the central part of the study area by 116 Ma and reached a peak in the Late Cretaceous (65 Ma). Hydrocarbon migration began at about 110 Ma with an expulsion efficiency of 0.77. At the present day, ∼100% transformation of reactive kerogen into hydrocarbons has taken place in the central part of the study area, with random gas migration within Cenomanian and Albian reservoirs. Modelled oil migration likely influenced by hydrodynamic factors is down-dip (westwards), towards deeper-water, more distal parts of the basin.

Gas saturation on a reactivated listric fault, which was ∼100% saturated at 93 Ma, declined to ∼15% by 65 Ma. This decrease in gas saturation is linked to uplift of the African margin in the Late Cretaceous which resulted in fault reactivation and re-migration of gas.

Despite the uncertainties which are associated with petroleum systems modelling, the study provides an insight into hydrocarbon migration in the northern part of the Orange Basin and contributes to the de-risking of future oil and gas exploration in this area.

Integrated sedimentological, diagenetic and structural analyses have been carried out on microporous and tight Urgonian (Barremian – Aptian) limestones in a study area in SE France in order to understand the influence of diagenetic changes and structural deformation on the spatial distribution of reservoir properties. A diagenetic history for the carbonates was established and was divided into phases which correspond to episodes of regional geodynamic activity. Petrographic (optical, SEM and cathodoluminescence microscopy), structural and geochemical (δ¹⁸O, δ¹³C) studies were carried out to characterize the cement phases in the carbonates, especially micrite and blocky calcite, and to investigate their relationship with episodes of fracturing.

Eleven calcite cement phases and four micritic cement phases were identified in relation to the two main phases of structural deformation which affected the Urgonian limestones. A first phase of micrite cementation occurred early in the diagenetic history and was linked to early marine cementation at the tops and bases of depositional cycles during the Barremian. A major phase of micrite recrystallization, which generated microporosity in carbonates that had previously been preserved from early cementation, was followed by a first phase of blocky calcite which occluded intergranular pore spaces. The blocky cement formed in a shallow burial meteoric environment and contributed to the preservation of microporosity during late Durancian tectonism (Albian – Cenomanian). A second phase of blocky calcite is associated with fracture activation during latest Eocene (Priabonian) – Oligo-Miocene extension.

Reservoir rock-types (RRTs) proposed in a previous study were consistent with the diagenetic characteristics and the results of δ¹³C / δ¹⁸O analyses. Microporous RRTs formed as a result of early to late shallow burial processes and display low δ¹³C values; whereas cemented RRTs developed both due to early marine cementation (with high δ¹³C values) and/or as a result of cementation related to fluid flow linked to the reactivation of faults and fractures. This suggests that some late diagenetic and microstructural processes were pre-determined by early diagenetic changes in the carbonates. The resulting stratigraphic architecture consists of a vertical stacking of weakly fractured microporous limestone intervals alternating with highly fractured, cemented limestone units.

The frequently stated problem of under-delivery in oil and gas exploration is largely due to overprediction in the volumetric size of prospects rather than to the misinterpretation of risk. In an effort to deal with the significant degree of uncertainty inherent in sub-surface evaluations, the standard method involves building a stochastic volumetric model of the potential container by choosing distributions and probabilities of the gross rock volume, the simulated column height, and the average 3D net/gross, as well as of other reservoir and fluid parameters. Unfortunately, prior to drilling, the three main inputs to the model are difficult to constrain as they are closely tied to the seismic interpretation rather than to historical information. By contrast, a source of hard data is available from existing discoveries and wells in the form of statistics for the play or analogue play, the most useful of which are: (i) the footprint area of the discoveries; (ii) the properties of net reservoir, encapsulated in an area yield parameter MMboe/km²; and (iii) the downside size of the discoveries, specifically the inferred P99 recoverable resource. In this paper, we propose a method called Prospect Area Yield (PAY) to assess the potential size of an exploration prospect which simply integrates these statistical data with the most reliable information from seismic mapping. The main step involves calculating an upside volume by multiplying a mid-case MMboe/km² yield with a mapped reasonable closure area for the prospect. This upside volume is assigned a probability which is currently assumed to be P10, implying that 90% of discovery outcomes will be smaller. A probabilistic distribution of the recoverable resource for the prospect is then produced by using the upside volume (P10) and the inferred P99 to construct a lognormal trend. The method can be tested by companies using lookbacks to fine-tune the probability of the upside volume to ensure that exploration predictions effectively match historical reality. In the meantime, it is recommended that the PAY method, which is available as a free online tool, is used as a check on the results of stochastic models.