Petroleum Geoscience - Volume 30, Issue 3, 2024

To clarify the movement of the water flooding front in fluvial reservoirs, this research takes the BZ oilfield as an example. By considering the equivalent flow resistance theory for oil–water two-phase flow, the horizontal micro-element equivalent method and the strong heterogeneity of fluvial facies reservoir comprehensively, a calculation model for a non-piston water flooding front in a horizontal well pattern was established. First, five horizontal injection–production well groups in the BZ oilfield were taken as examples to calculate the water breakthrough time for the oil wells. The calculation results are in good agreement with the actual production performance. In detail, the advancing speed of the water flooding front in the high-permeability strip was 0.8–1.6 m/day, and the speed in the low-permeability strip was 0.12–0.35 m/day. When water is seen in the oil well, the advancing speed in the low-permeability strip is reduced, resulting in uneven displacement and the formation of non-dominant potential areas. In addition, the water flooding front advancing distance was simulated to be 300–450 m by establishing a reservoir numerical simulation model, which is close to the result of the proposed model, indicating that the calculation method is reliable. This research is of great significance for predicting the water breakthrough time of horizontal production wells, judging the weak affected area on the mainstream line, and optimizing water injection and tapping reservoir potential in good time.

In hydrocarbon exploration, total organic carbon (TOC) content and Rock-Eval pyrolysis are commonly employed geochemical techniques that offer concise insights into kerogen type, effective source-rock identification and thermal maturity. In the current study, the data obtained from Rock-Eval pyrolysis has been used to define the source-rock quality, generative potential, kerogen type, maturity of the source sediments and kerogen kinetics of the Baisakhi–Bhadesar Formation of Kimmeridgian–Tithonian (154.7–145.6 Ma) age. Basinal level hydrogen index (HI), TOC content, source-rock maturity, transformation ratio and heat-flow maps have been generated by integrating the data from pyrolysis with previously available data from wells drilled in the basin. The TOC content of the Kimmeridgian–Tithonian sequence ranges from 0.03 to 12.71% in the studied samples, with an average TOC content of 1.28%, indicating good source-rock quality. The HI, in collaboration with T max and vitrinite reflectance (VRo) data, demonstrates that the Baisakhi–Bhadesar Formation is characterized by type II, a mixture of type II/III and type III kerogen facies and exhibits good source-rock quality and poor to good generative potential in the basin. The studied samples are marginally mature to mature in nature (T max, 430–450°C; VRo, 0.52–0.72%). A maturity analysis of the basin suggests that during the Late Jurassic most areas were under the oil window zone, except for the Bhakhari Tibba and Miajlar areas. The transformation ratio overlay for the Kimmeridgian–Tithonian source sequences shows better transformations of the source rock in the area of the Shagarh Sub-basin. Kerogen kinetics of the studied Baisakhi–Bhadesar Formation demonstrate that the activation energy ranges between 46 and 74 kcal mol−1 with the significant distribution of activation energy being 54 kcal mol−1 (42.07%), representing a strong heterogeneous type of organic matter in the sediments. Based on lithological, palaeontological and electrolog studies, a shallow-marine to nearshore environment of deposition with a sediment-input direction from the SE has been inferred for the Kimmeridgian–Tithonian sequences. The results of this study quantitatively establish the role of the Kimmeridgian–Tithonian sequence as a source rock, ultimately contributing to the generation of hydrocarbons in the basin along with spatial changes in the quality of source sediments in different parts of the basin.

This paper covers a novel micro-level application of image processing in understanding the topological and petrophysical properties of Indian Gondwana shale using X-ray computed microtomography images. The complexity and randomness in the pore system are explained through the concept of fractal dimension (FD). In this paper, a quantitative analysis of 2D and 3D fractal dimensions of pores, grains and interfaces was performed for Indian Gondwana shale, using the box-counting method. A pore network is formed by the connection of many subpore clusters, each with a different volume. Hence, an image segmentation algorithm was applied to label different subclusters, and subsequently an analysis of FD was carried out on such subclusters of pores and grains. We implemented a novel application of Betti numbers (B0, B1 and B2) and Euler characteristics on our sample and calculated the possible flow channels of the sample. The FD of grains was found to be greater than the FD of the pore–grain interfaces, while the FD of pores was found to have the smallest value. Consequently, we also observed how the FD of both pores and grains was majorly controlled by the largest subcluster, and during fluid intrusion we observed a significant decrease in the FD of pores. Finally, the pore network with a larger B0 and larger difference of B1 was proved to be best for the storage of hydrocarbons and for fluid movement along more flow channels.

In fold-and-thrust belts where there is a high degree of structural complexity, artificial geometrical distortions are often present on seismic reflection profiles. These need to be minimized during modelling. We document a workflow in which depth mapping, velocity model building, well calibration and cross-section balancing are integrated into the seismic interpretation process to generate trustworthy structural models in complex zones. The proposed methodology is exemplified by a case study from the foothills zone of the Colombian Eastern Cordillera. In addition, sequential kinematic restoration of the modelled structure allowed an evaluation to be made of hydrocarbon migration routes during the period between the Oligocene and the middle Miocene. Following the previously mentioned workflow, we document a failed exploratory case study where all elements of the petroleum system are present except the trap. In this context, the documented case is a typical velocity pull-up. From this and published case studies, we conclude that in Andean settings and probably most on land contractional-foothill settings, the use of seismic images only does not provide enough evidence for the presence of traps and additional surface geological signatures must be documented. The proposed workflow therefore appears to be a useful tool for evaluating the exploration risk in structurally complex fold-and-thrust belt settings.

The petroleum potential of onshore basins in Colombia has been partly controlled by the Andean Orogeny since the end of the Cretaceous. Its Axial Zone has at least one understudied active petroleum system with a rather low petroleum potential and few commercial medium to heavy oil accumulations, raising questions about how the Andean deformation influenced the petroleum system and the possible undiscovered accumulations. We examine the timing of this petroleum system in the Axial Zone through oil–source correlations and two 2D petroleum system models across the Boyacá and Soápaga faults based on cross-sections.

Modelling reveals the direct control of deformation on generation–accumulation in the Axial Zone, where the Lower Cretaceous source rocks, due to high heat flows during the synrift phase, started generation so early (100 to 60 Ma) that no reservoirs or traps were yet available to allow hydrocarbon entrapment and accumulation. Equally, for the younger Upper Cretaceous source rocks, the tectonic inversion of the basin between 33 and 23 Ma along the Boyacá and Soápaga faults interrupted burial and the maturation in most parts of the basin, leaving only local pods of active source rocks where maturation continues today due to the tectonic overburden along the footwall of the Soápaga Fault. The latter is thus the major kitchen, contributing more than 50% of the liquid hydrocarbons trapped mainly in Upper Cretaceous and Paleocene sandstones. Hydrocarbons migrate upwards where biodegradation and water washing occurred in the near-surface, giving rise to the many tar sand occurrences in the Eocene sandstones.

This paper combines quality-controlled pore pressure measurements and indicators with geophysical well logs from 310 deep wells to evaluate the pore pressure distribution in the overpressured North Alpine Foreland Basin in SE Germany. Previous studies relied chiefly on low-resolution check shots and vertical seismic profiles calibrated to only a few pore pressure measurements. The current study, based on sonic and electrical resistivity logs, indicates that more than one shale normal compaction trend is required to appropriately assess pore pressure from geophysical well logs. Thereby, the necessary adjustments of the derived compaction trends apply to both sonic and resistivity data, which possibly reflect a gradual change in the mineralogical composition with decreasing clay content or progressing cementation from north to south or an increase in horizontal loading-driven compaction towards the North Alpine Thrust Front. The newly derived compaction-based pore pressure distribution is combined with drilling data-based pore pressure evaluations and offers a comprehensive update of previous pore pressure investigations in the North Alpine Foreland Basin. Our study is therefore of key importance for optimized well planning and cost-effective drilling in the course of the recent expansion of deep geothermal energy exploration in the overpressured North Alpine Foreland Basin.