Petroleum Geoscience - Latest issue

Shale gas, a clean energy source with large reserves and wide distribution, is gaining global attention. The Nanpanjiang Basin, in the southern part of Yangtze Block, is a strategic area for marine shale-gas exploration, with the Tian'e region as a key target. Field investigations and previous studies have confirmed the distribution of Lower Devonian Tangding shale in the Nanpanjiang Basin. This study, using organic geochemistry, X-ray diffraction and scanning electron microscopy, analysed the geochemical characteristics of source rocks, shale reservoir properties, gas content and preservation conditions. The Tangding shale is 100–250 m thick, with burial depths of 2100–4200 m. The total organic carbon (TOC) values of the shales exceed 2.0 wt%, comprising mainly kerogen types Type II1–II2 and high- to over-mature organic matter, indicating excellent source-rock potential. The shales contain a high percentage of brittle minerals, with well-developed pore spaces and adsorption capacities, suggesting a good shale-gas reservoir. A relatively high clay mineral content, along with strong compaction and cementation, enhances the shale's self-sealing capacity, ensuring good preservation conditions for shale gas. The gas content is relatively high, indicating significant shale-gas accumulation. Multi-episode tectonic movements have significantly influenced shale-gas preservation. Compared with typical shale-gas accumulation conditions in other basins, the Tangding shales in the Tian'e area offer favourable conditions for shale-gas accumulation, making the northwestern part of the Tian'e area an important target zone for shale-gas exploration in the Nanpanjiang Basin.

The Termit Basin, a well-explored hydrocarbon-rich basin in West Africa, provides an excellent case study for investigating oil families, palaeoenvironments and organic matter (OM) inputs in the Trans-Saharan epicontinental basins. This study examines 19 newly discovered southeastern oils using gas chromatography, gas chromatography-mass spectrometry and stable carbon isotopic analysis. While three oil families (I, II and III) were previously identified in the basin based on discoveries made prior to 2020, this study identified, for the first time, family I oils in the far east of the basin, and first recognized two new families (IV and V) by chemometric analysis and correlations of 14 biomarkers and carbon isotope compositions. Families I and IV show more terrigenous inputs than family V. Our results do not support previous work suggesting that family I was derived from algal-dominated OM. Compared with family I, a contribution of marine sources was defined for family IV, although terrigenous inputs remained significant. Family V originated from source rocks with more inputs of marine OM. Family V is divided into subfamilies V1 and V2, of which subfamily V2 is distinguished by greater algal inputs under more reducing conditions. The identification of family V proved the presence of a new petroleum system related to marine algal-rich source rocks in the Termit Basin. Our results suggest significant terrigenous OM influx and extensive marine algae blooms in the Trans-Saharan epicontinental seas during the Late Cretaceous, coinciding with sea-level changes.

Dielectric permittivity mixture models often assume simplified rock geometries, limiting their accuracy in rocks with complex pore structures. Systematically evaluating the influence of pore geometry, grain shape and grain size on model performance for water-saturation assessment is experimentally challenging and thus largely untested. Frequency-domain dielectric permittivity simulations, however, provide a means to effectively model these geometrical influences at the pore scale. Therefore, this paper aims to: (1) investigate the influence of grain geometry (size, shape and alignment) on dielectric permittivity using synthetic samples; and (2) evaluate the mixture model performance in assessing water saturation in synthetic and actual rocks. We performed frequency-domain simulations in the frequency range of 10 Hz–5 GHz. The dielectric permittivity dispersion significantly increased as grains flattened (i.e. the aspect ratio increased). The frequency-domain simulations conducted over the range of 10 MHz–5 GHz showed that grain size had a negligible impact on permittivity above 10 MHz. We observed that the relative permittivity in the z direction decreased with an increased aspect ratio of the grains. Simulations suggested that directional permittivity measurements can enhance grain-shape characterization. The unique contribution of this paper is the comprehensive quantification of the impacts of grain size, shape and alignment on the dielectric permittivity. Conducting such an investigation is challenging and almost impossible in the core-scale domain.

Abundant microbial dolomite reservoirs have been discovered worldwide. However, their complex pore structures, controlled by various microbial textures and diagenesis imprint, are poorly understood, which constrains hydrocarbon production in microbial dolomite. The Middle Triassic Leikoupo Formation microbial dolomite in the western Sichuan Basin provides a typical example to decipher the controls of pore structure in microbial dolomite through integrated studies of petrography, high-pressure mercury injection and micro-CT imaging of rock samples from outcrops and cores. The sedimentary environment, and the hydrodynamic conditions in particular, plays a significant role in determining the multiscale textures of microbial dolomite. The pore structures are affected by the different micro-textures that influence the overall pore-throat characteristics, including morphology, stratification and original connectivity. Diagenetic processes play a crucial role in altering pore structures, with differences observed in the pore distribution due to cementation or dissolution. In the thrombolites, densed micrite thrombolites, porphyritic micrite thrombolites and peloidal-aggutinated thrombolites typically exhibit micro-pore throat dominance with a bimodal distribution, but may display meso- and macro-pore throats under dissolution or weak–moderate cementation. For the foam laminated thrombolites, the pore-throat distribution is typically unimodal, with micro- or meso-pore throats influenced by the intensity of cementation. Stromatolites commonly show a bimodal pore-throat distribution, with size variations dependent on cementation and the intensity of dissolution. Strongly cemented agglutinated thrombolitic stromatolites and spongiostromate stomatolites exhibit micro-pore throat dominance, whereas laminated fine-grained agglutinated stromatolites and skeletal stromatolites display a mixture of micro- and meso-pore throats. Moderate cementation or dissolution may result in a mix of micro- and meso-pore throats in agglutinated thrombolitic stromatolites, while spongiostromate stomatolites and skeletal stromatolites may show meso- and macro-pore throats.

The organic-rich shale facies of the Lower Jurassic Datta Formation in the Upper Indus Basin in Pakistan was studied using geological and geochemical investigations to assess the unconventional shale oil reservoir potential. The Datta shale facies is a promising oil-prone stratum, consisting of total organic carbon (TOC) exceeding 2 wt%, and primarily comprising Type II and II/III kerogens, with a hydrogen index (HI) exceeding 250 mgHC g−1 TOC. The Datta shale facies is also characterized by higher free hydrocarbon (S1) content than TOC, resulting in a high oil saturation index (OSI) between 30.81 and 298.7 mgHC g−1 TOC, wherein the high OSI of more than 100 mgHC g−1 TOC indicates a strong potential for oil production. This finding is consistent with the current thermally mature oil window, which ranges between early mature and peak mature, as supported by vitrinite reflectance (%VRo) values of up to 0.82. This main oil-generation window leads to the conversion of extensive hydrogen-rich kerogen for commercial oil generation, with a transformation ratio (TR) of up to 65%, as demonstrated by 1D basin modelling. Maximum oil generation, with TR values exceeding 50%, leads to high pressure and results in microfracture pores in the Datta shale facies. The presence of non-fabric-fracture pores is confirmed by high-resolution petrographical scanning electron microscopy (SEM). Consequently, these findings highlight that the Datta shale facies should be considered for use as an unconventional shale oil reservoir, with the suggestion of hydraulic fracturing techniques for production purposes.

The seismic interpretation of very thin to thin turbiditic sandstones, particularly when intercalated with siltstones and shales, presents challenges, complicating the exploration and production of hydrocarbons. One of the most significant issues in this environment arises from seismic resolution, which typically cannot resolve thicknesses below 10–20 m. This was observed in the post-salt section of the Brazilian offshore basins. To address this challenge, we improved the seismic resolution by applying the time–time (TT) transform and combining local frequency, phase and magnitude components. Compared to conventional seismic attributes, the attributes derived from the TT transform allowed us to identify depositional turbiditic elements within the turbidite system as outlined in the literature and used as a conceptual model. By adopting this combination, we developed reliable architectural models that correlated well with wellbore information. From these outputs, it is feasible to build robust geological models that provide enhanced information for better project decision-making, enabling project specialists to manage inherent uncertainty and increase profitability.

Advancements in seismic imaging using neural networks have significantly improved geological characterization. Fully convolutional networks (FCNs), particularly UNet-based architectures, have demonstrated high accuracy in predicting acoustic velocity models from raw seismic data. However, traditional approaches often overlook critical spectral features, such as wavelet positioning and phase rotation, which are essential for refining seismic predictions. A spectral recomposition approach for estimating the temporal position of wavelets in a seismogram is employed so that this information can be incorporated to train a FCN to predict velocity models of geological structures. In addition, critical angle information to enhance the training dataset is used with the objective of predicting downdip layers more accurately. Both critical angle information and wavelet positions in time are incorporated in the training process for the neural network as additional features. As the critical angle is barely reached in seismic acquisition on deeper structures, reflections in downdip layers present a wider reflection angle, which might be identified as a sharper critical angle by some techniques. This information, treated as a feature for increasing information to train a FCN, has been shown to be capable of predicting acoustic velocity models more accurately, especially for the shape of downdip structures.

Secondary migration is poorly understood and the generally favoured transport mechanisms fail to explain many of its apparent characteristics. Here, building on work originally developed in the1940s, I resurrect an old hypothesis of migration as a colloidal dispersion but in more detail than hitherto. This contribution expands on this hypothesis of migration with a focus on its theoretical mechanisms, limitations and advantages. The aim is to develop a self-consistent model to demonstrate how this transport mechanism might work. A better understanding of secondary migration of petroleum has implications for conventional and unconventional plays, and for reservoir diagenesis.

The hypothetical model for colloidal secondary migration, presented in part I, is tested here with numerical models to examine its viability and to determine the conditions under which it becomes ineffective. The main assumptions are that petroleum migrates as a Pickering emulsion of individual nanodroplets (a few tens of nanometres in size) and groups or ‘flocs’ of nanodroplets. These are nanodroplets are protected from coalescence by coatings of silica, asphaltenes and clay fines. Migration is achieved by diffusion (Brownian motion) of the nanodroplets, and advection of the flocs, working together cooperatively. The cases tested here with numerical models are:

(1) Oil migration into an anticlinal structure (e.g. Ghawar Anticline, Saudi Arabia);

(2) Gas migration into an anticlinal structure (e.g. Ghasha Anticline, United Arab Emirates);

(3) Migration within a tight gas sandstone in a foreland basin (e.g. Niobrara gas field, Rock Island gas field, USA);

(4) Migration within a tight oil sandstone in a foreland basin and its effects on a tight (shale) gas reservoir (e.g. Powder River Basin, USA);

(5) Migration of heavy oil in a foreland basin (e.g. Western Canada Sedimentary Basin); and

(6) The role of colloidal migration in reservoir diagenesis.

The main implications of the model in these situations are:

(1) and (2) Colloidal migration is highly efficient in the conventional oil and gas windows and is generally orders of magnitude faster than Darcy migration.

(3) The mechanism breaks down rather abruptly in good carrier beds in the gas window, typically at a pore-throat size of c. 1 µm. It provides a satisfactory explanation for the filling of unconventional tight gas sandstones and their low water saturations.

(4) With lower-quality carrier beds, the mechanism breaks down in the late oil window, leading to tight oil carrier-bed plays.

(5) The colloidal mechanism can migrate heavy oils relatively fast and easily, compared with Darcy flow, because the main resistance is the viscosity of the porewater rather than that of the petroleum.

(6) Migrating Pickering emulsions provide an effective means of transporting inorganic matter long distances into traps. This has strong implications for reservoir diagenesis. For example, the mechanism can account for the observed trends of quartz cementation in petroleum traps and the timing of petroleum fluid inclusions in quartz overgrowth cements.

If this hypothesis is substantiated by direct observation of the proposed petroleum nanodroplets, many traditional concepts of petroleum systems will have to be revised.

Northern Egypt and its Western Desert region are hydrocarbon provinces that record important Mesozoic extension, yet Jurassic and older synrift strata are still poorly characterized in these two areas, particularly in the onshore Shushan Basin. This work uses seismic-reflection data tied to borehole and geochemical data to investigate three main Jurassic synrift seismic and depositional megasequences in the Shushan Basin: (1) a Lower Jurassic retrogressive megasequence; (2) a Middle Jurassic prograding megasequence; and (3) an Upper Jurassic retrogressive megasequence. These megasequences, defined for the first time in this work, accompanied Late Triassic–Early Cretaceous tectonic extension, with deposition occurring in proximal environments such as rivers, lakes and deltas. Terrigenous organic matter was preserved over long periods of time within clay-rich source intervals, as confirmed via organic geochemical analyses. Significantly, the presence of Type II and Type III kerogen, and a total organic carbon content of up to 3.91% suggest good hydrocarbon source-rock potential in specific Jurassic intervals. One-dimensional burial models suggest that, with sufficient burial, these source intervals generated oil and gas with a recorded maximum yield in the Early Miocene. As a corollary, this work indicates that conventional and unconventional hydrocarbon exploration targets exist in the Shushan Basin. The results show Middle Jurassic shale-rich intervals to be prime tight-gas targets, while Upper Jurassic carbonate units are promising conventional reservoirs in both the central and southern parts of the basin. The high formation temperatures recorded show that geothermal options are also feasible for deep wells, expanding the economic importance of northern Egypt.