Petroleum Geoscience - Current Issue

More than 20 pinnacle reefs have been discovered in the SE of the Ajdabiya Trough within Paleocene carbonate sediments, most of which are oil-bearing. However, detailed reservoir characterization and conditions governing oil fill-up in this reef have remained unresolved. The major faults provide paths for significant vertical movement of fluids at the edges of the Intisar reef reservoirs. At the same time, the ongoing karst solution collapse also creates vertical zones for fluid encroachment both outside of and within the productive area of the Intisar reef reservoirs. The seismic data show numerous karst-collapse features up to 300 m in diameter that developed shortly after the final drowning of the Intisar ‘B’ and ‘C’ reefs. These karst-collapse features may be the main contributing factor in the escape of hydrocarbons within these reefs, which could explain the high water cuts in the Intisar ‘B’ and ‘C’ reefs. However, the porosity of the southeastern part of the Intisar ‘A’ reef has been significantly improved by fracturing and dissolution, as faults associated with fractures are very common in this part of this reef.

A 3D subsurface structural model was built in a zone of the Greater Bay du Nord area, Flemish Pass Basin, offshore Newfoundland and Labrador, to carry out a post-drilled, fault-seal analysis in a multi-rift, geological complex setting; this aimed to test fault-seal predictions, calibrate computed static fault-zone attributes and estimate hydrocarbon contact depths.

Hydrocarbon exploration campaigns in the Greater Bay du Nord area have primarily targeted rotated fault blocks that often exhibit structural segmentation and compartmentalization. A comprehensive approach that combines empirical and deterministic methods for static fault-seal analysis has been implemented. This approach provides insights into open, base and tight fault-seal scenarios, aiding prospect evaluation in this region. Notably, shale gouge ratios (SGRs) in the range 16–25% serve as a crucial indicator of the transition between fault-rock sealing and non-sealing fault segments. Furthermore, it emphasizes the critical role of hydrodynamics when calibrating or evaluating fault-sealing properties.

In areas like the Greater Bay du Nord region, characterized by complex geology, it is imperative to regularly update fault-seal models. These updates should align with the availability of new subsurface data, comprehensive analyses and an improved understanding of the petroleum system.

Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Former coal mines hosted in Upper Carboniferous silt- and sandstones in the Ruhr Basin, NW Germany, are currently examined for post-mining applications (e.g. geothermal energy) and are also important tight-gas reservoir analogs. Core material from well Pelkum-1, comprising Westphalian A (Bashkirian) delta deposits, was studied. The sandstones and siltstones are generally tight (mean porosity 5.5%; mean permeability 0.26 mD). Poor reservoir properties primarily result from pronounced mechanical compaction (mean COPL 38.8%) due to deep burial and high contents of ductile rock fragments. Better reservoir properties in sandstones (>8%; >0.01 mD) are due to (1) lower volumes of ductile grains (<38%) that deform during mechanical compaction and (2) higher volumes in feldspar and unstable rock fragments. During burial these form secondary porosity (>1.5%) resulting from acidic pore water from organic matter maturation. Still, sandstones with enhanced porosities only show a small increase in permeability since authigenic clays (i.e. kaolinite and illite) or late diagenetic carbonates (i.e. siderite and ferroan dolomite/ankerite) clog secondary porosity. Quartz cementation has a minor impact on reservoir properties. Evaluating the Si/Al ratio can be a suitable proxy to assess grain sizes and may be a convenient tool for further exploration.

Supplementary material: Lithologs and petrophysical data of well Pelkum-1 are available at https://doi.org/10.6084/m9.figshare.c.7003156

Although pore geometry plays an important role in carbonate rock physics modelling, few studies have been carried out on its analytic relationship with other pore space properties such as pore space stiffness. We propose an analytical workflow based on the differential effective medium (DEM) to estimate the elastic properties of carbonate rocks. The validity of our results is then cross-checked with the Xu and Payne model on a real carbonate dataset. This workflow establishes a direct and quantitative link between the pore geometry of carbonate rock and its other pore space properties such as the Biot coefficient and pore space stiffness. This relationship can, furthermore, be utilized in defining rock physics templates (RPTs) to investigate the role of pore geometry on the rock elastic properties. Furthermore, we extended the Biot–Gassmann–Krief (BGK) model through our proposed workflow by establishing a theoretical framework to relate the main components of the BGK model to the pore geometry usually estimated in the laboratory or empirically. This can help to investigate the impact of fluid substitution on each of these main components. Our investigation suggests that the higher the Biot and Gassmann coefficients, the more sensitive the rock is to fluid substitution. Moreover, this analytical workflow has been employed to examine the role of selecting different rotational spheroids (i.e. oblate and prolate) on the modelled velocities. Our results show that the modelled velocities depend on this selection in such a way that prolate pores are less sensitive to the variations in their pore aspect ratio compared with oblate pores.

In this study we used the concept of inverse rock physics modelling to analyse reservoir properties of the Kanywataba Exploration Area, with a focus on their lateral distribution away from the Kanywataba well. The procedure employed rock physics models calibrated for the basin constrained by seismic inversion data, where non-uniqueness and data error propagation issues were also taken into account. Both seismic and well log datasets were used in the data calibration. The procedures enabled us to obtain the most likely estimate mean, weighted mean and posterior mean of the reservoir properties. We obtained a good match between measured and modelled porosity values. Any misfit between the observed and predicted lithology was mainly attributed to uncertainties in defining the correct mineral properties. The integrated approach revealed that high porosities correlate with low clay volumes and, furthermore, indicated two distinct reservoir units in the basin, which were interpreted as the Oluka and Kakara Formations. Fluid saturation data were less successfully predicted but this was most probably due to a result of lack of real saturation logs for use in the calibration of the rock physics model; instead, predicted saturation logs based on Archie's law were used in the calibration process. This analysis is first of its kind in this basin and therefore exhibits a high level of novelty in the determination of reservoir properties in this area.

Fracture networks play a critical role in fluid flow within reservoirs, and it is therefore important to understand the interactions and influences of these networks. Our study focuses on the Southern Chotts–Jeffara Basin, which hosts reservoirs within Triassic, Permian and Ordovician units containing significant hydrocarbon accumulations. Recent developments on the structural understanding of the basin have proved that a regional shortening phase occurred between the Permian and Jurassic, forming open folds and a distributed fracture network. Analysis of late Paleozoic and Mesozoic outcrops within the basin has identified several sets of fractures (with dip directions and dip angles of 150/80 and 212/86) and compressional structural features that support this shortening hypothesis. We have integrated fracture data from surface analogues and subsurface analysis of advanced seismic attributes and well data through structural linking to form a 2D hybrid fracture model of the reservoirs in the region. Through analytical aperture modelling and numerical simulation, we found that the fractures orientated 212° in combination with large-scale fractures contribute significantly to the fluid-flow orientation and potential reservoir permeability. Our presented fracture workflow and framework provide an insight into network characterization within naturally fractured reservoirs of Tunisia, and how certain structures form fluid pathways that influence flow and production.

Supplementary material: Data and figures detailing fracture characterisation and modelling along open folds in southern Tunisia are available at https://doi.org/10.6084/m9.figshare.c.6904499

Reservoir quality in carbonates is influenced by various factors such as the depositional environment, burial history and diagenesis processes. Understanding these geological heterogeneities is essential for successful petroleum exploration. This study characterizes Brazilian pre-salt reservoirs and aims to understand how their heterogeneity impacts reservoir quality. We analysed carbonate samples from the Barra Velha Formation (Santos Basin) through an integration of petrographical and core plug descriptions, petrographical facies characterization, porosity and permeability measurements, and image analysis to identify the principal controls on porosity and permeability, pore-size distribution, and groups with similar petrophysical properties using the hydraulic flow unit (HFU) concept. Five facies groups were recognized: Spherulitestone (F1); Shrubstone (F2); Intraclastic Grainstone (F3); Intraclastic Packstone, Spherulitestone with mud and Shrubstone with mud (F4); and Shrub–Spherulite Intercalations and Bioclastic Grainstone (F5). The analysis of porosity and permeability showed that their variations are associated with pore type and cementation rate. Greater contributions of inter-aggregate, interparticle and vugular porosity, combined with a reduced amount of cement, results in higher porosity and permeability but an increase in cement tends to reduce the porosity and permeability. Among the facies groups, F2 and F3 exhibited the best porosities and permeabilities, followed by F1, F4 and F5. From image analysis, small pores (1.5 × 10−5–0.01 mm2) are the most common in all rocks. However, these small pores contributed significantly to total porosity only in F4 and some samples of F3. For F2 and F3, the large pores (from 0.01 mm2 to a maximum of 19.62 mm2) are the main contributors, while F5 has a homogeneous contribution. Finally, the data were grouped into five HFUs: HFU1 and HFU2 represent the zones with the best reservoir quality, primarily composed of F2 and F3.

This study develops an innovative workflow to identify discrete lithofacies distributions with respect to the well-log records exploiting two tree-based ensemble learning algorithms: extreme gradient boosting (XGBoost) and adaptive boosting (AdaBoost). In the next step, the predicted discrete lithofacies distribution is further assessed with well-log data using an XGBoost regression to predict reservoir permeability. The input well-logging records are gamma ray, neutron porosity, bulk density, compressional slowness, and deep and shallow resistivity. These data originate from a carbonate reservoir in the Mishrif Basin of southern Iraq's oilfield. To achieve a solid prediction of lithofacies permeability, random subsampling cross-validation was applied to the original dataset to formulate two subsets: training for model tuning and testing for the prediction of subsets that are not observed during the model training. The values for the total correct percentage (TCP) of lithofacies predictions for the entire dataset and testing subset were 98 and 93% using the XGBoost algorithm, and 97 and 89% using the AdaBoost classifier, respectively. The XGBoost predictive models led in attaining the least uncertain lithofacies and permeability records for the cored data. For further validation, the predicted lithofacies and reservoir permeability were then compared with porosity–permeability values derived from the nuclear magnetic resonance (NMR) log, the secondary porosity of the full-bore micro imager (FMI) and the production contribution from the production–logging tool (PLT). Therefore, it is believed that the XGBoost model is capable of making accurate predictions of lithofacies and permeability for the same well's non-cored intervals and other non-cored wells in the investigated reservoir.

Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a useful opportunity to try to understand subsurface fracture networks in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in the southern Sichuan Basin, four types of natural fractures were identified in terms of orientation, size, filling properties and spatial distribution. Uncemented bed-parallel shear fractures develop at or in the vicinity of mechanical interfaces and are inclined to present in shale layers with a dip angle greater than 12°. Cemented bed-parallel fractures are characterized by a crack-seal texture marked by multiple bands of fibrous cement, and their intensity decreases upwards and shows a positive relationship with total organic carbon (TOC) values. Uncemented bed-oblique fractures are a type of fracture that rarely develops, and accommodate limited open space. Cemented bed-oblique/perpendicular fractures are the most developed fracture type and are distributed on a regional scale and are subdivided into two types. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability, yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.

Pervasive igneous intrusive complexes have been identified in many sedimentary basins which are prospective for petroleum exploration and production. Seismic reflection and well data from these basins has characterized many of these igneous intrusions as forming networks of interconnected sills and dykes, and typically cross-cutting sedimentary host rocks. Intrusions have also been identified in close proximity to many oil & gas fields and exploration targets (e.g. Laggan-Tormore fields, Faroe Shetland Basin). It is therefore important to understand how igneous intrusions interact with sedimentary host rocks, specifically reservoir and source rock intervals, to determine the geological risk for petroleum exploration and production. The risks for petroleum exploration include low porosity and permeability within reservoirs, and overmaturity of source rocks, which are intruded. Additionally, reservoirs may be compartmentalized by low permeability igneous intrusions, inhibiting lateral and vertical migration of fluids. Based on a range of field studies and subsurface data, we demonstrate that sandstone porosity can be reduced by up to 20% (relative to background porosity) and the thermal maturity of organic rich claystones can be increased. The extent of host rock alteration away from igneous intrusions is highly variable and is commonly accompanied by mechanical compaction and fracturing of the host rock within the initial 10 to 20 cm of altered host rock. Reservoir quality and source rock maturity are key elements of the petroleum system and detrimental alteration of these intervals by igneous intrusions increases geological risk and should therefore be incorporated into any risk assessment of an exploration prospect or field development.

Thematic collection: This article is part of the New learning from exploration and development in the UKCS Atlantic Margin collection available at: https://www.lyellcollection.org/topic/collections/new-learning-from-exploration-and-development-in-the-ukcs-atlantic-margin