Petroleum Geoscience - Volume 30, Issue 4, 2024

Exploration and development practices have proved that fracturability evaluation is the primary basis for successful fracturing operations. Current studies mainly rely on using traditional physical parameters to evaluate shale fracturability. However, fracture morphology and the extension of natural fractures during fracturing are also crucial for shale fracturability evaluation. In this study, correlations between factors and rock fracture complexity and the degree of natural fracture opening were analysed using 40 sets of related experiments, and a new method is proposed for shale fracturability evaluation that considers Young's modulus, the shear expansion angle, residual strain, the approach angle and the stress variance coefficient. Finally, taking the shale gas field in the Sichuan Basin as an example, a comprehensive evaluation model of shale fracturability was established using the grey correlation method combined with core experimental data. One well was selected in order to compare and analyse the fracturability profile with the stimulated reservoir volume. The results show that peak strain has the most significant influence on shale fracture complexity, followed by the shear expansion angle and Young's modulus. The approach angle and the stress difference coefficient affect the degree of natural fracture opening at the same time. The model is accurate because the fracturability values match the study block's stimulated reservoir volume data. This new method of shale fracturability evaluation provides important technology for predicting the fracturability of shale gas reservoirs and optimizing operation schemes.

The complexity of marine gas hydrate systems at the Peruvian convergent margin has been linked to the post-Miocene history of vertical tectonics and subduction erosion that affected the forearc. Here, multichannel seismic data and published findings reveal that such a complexity has been further extended by the occurrence of the pre-Miocene deep Morsa Norte Graben (MNG) off Trujillo (8°–9° S) in the Central Peru margin. At water depths of 650–750 m in the upper slope, directly above the MNG depocentre (which has a 4–6 km overburden thickness), continuous bottom-simulating reflections (BSRs) and concentrated sub-BSR high-amplitude reflections are confined beneath a layered basin with a low–moderate near-seafloor heat flow (7–33 mW m−2). A deeper BSR modelled with a thermogenic gas composition is associated with the enhanced reflections. At a water depth of 900 m, sub-BSR reflections become less frequent in an area with a layered sediment cover defined by a moderate near-seafloor heat flow (15–33 mW m−2). At a water depth of 1200 m, where the MNG is relatively thick (3–4 km overburden thickness), faults connect patchy BSRs with a moderate–high near-seafloor heat flow (52–110 mW m−2). There, sub-BSR enhanced reflections are scarce. Immediately above the top of the gas hydrate stability zone (GHSZ), the near-seafloor heat flow reaches 81 mW m−2. Modelling suggests a water depth-dependent transport of heat towards the seafloor with respect to the top of the GHSZ, implying that the closer the seafloor is to the top of the GHSZ, the lower the advection of heat, and vice versa. Recent seafloor-related depositional and structural features amplify such relations in agreement with near-seafloor heat-flow variability. However, towards the area outside the extent of the MNG (<3 km overburden thickness), continuous BSRs are not linked either to a deeper BSR or to sub-BSR enhanced reflections. The continuity of one of these BSRs is deflected upwards beneath a slump, suggesting an incomplete thermal re-equilibration of the GHSZ. Therefore, we conclude that the BSR responds to: (1) the confinement and thickening of the free-gas zone (FGZ) above the MNG depocentre due to the sealing effect of recent sedimentation close to the top of the GHSZ; (2) the seepage of gas-rich fluids from a thinned FGZ above the relatively thick MNG, due to the enabling effect of faults cutting the GHSZ far from the top of the GHSZ; (3) the undisturbed state of the FGZ outside the extent of the MNG; and (4) the disequilibrium state of the base of the GHSZ due to the unloading of sediments in an unstable slope environment prone to failure.

As producing fields enter late life, successful mitigation of subsurface risk is critical in order to justify continued infill well drilling. Despite penetrations by more than 100 wells and the availability of modern 3D seismic across the Scott and Telford fields (Outer Moray Firth, UK Central North Sea), reservoir absence has led to repeated development well failures. A new model now attributes reservoir attenuation to Late Jurassic footwall uplift and erosion.

The 2015 Scott J40 well encountered a reduced Upper Jurassic reservoir section of Lower Scott sands, with Upper Scott and Piper sands absent. Reinterpretation ascribed reservoir truncation to the effect of Late Jurassic footwall uplift and erosion rather than fault cut-out as previously interpreted. The failed 2016 Telford F6 well was shown to have drilled a thick Kimmeridge Clay hanging-wall section north of the Telford Fault, rather than the southern footwall section targeted. Planning for the Scott J43 and four subsequent wells implemented lessons learned from these failures and mitigated reservoir risk while optimizing reserves.

The Scott and Piper sand distributions are likely to reflect early growth folding before the main Mid-Kimmeridgian–Early Tithonian phase of NE–SW extensional faulting and footwall uplift, which saw the Piper and Scott reservoirs eroded at footwall crests and locally reworked as deep-water Claymore sands. Later Mid-Tithonian–Early Berriasian east–west faulting during the opening of the Witch Ground Graben saw major crestal synsedimentary erosion at Telford and continued erosion at the western crest of Scott Block 1b, while the footwall to the east was partially downfaulted.

Fractures and tectonic settings cause azimuthal anisotropy in reservoirs. Recognizing the fracture model from the seismic data is a useful tool for identifying the productive zone in reservoirs. We applied azimuthal velocity analysis in seismic processing to improve the image quality and to estimate the anisotropic model parameters. Using azimuthal residual moveout analysis, the direction of azimuthal anisotropy in the reservoir was predicted, and it was found that the results are consistent with fracture orientations obtained from image logs in the reservoirs. Bayes’ theorem and a cascaded procedure in least-squares inversion, which matched observed amplitudes to linearized Zoeppritz equations, were used to estimate the elastic moduli as a first step, and the normal and tangential fracture weaknesses were estimated in a second step. Laboratory experiments were carried out on core samples to validate the first-step inversion results. It was found that the propagation wavelets varied in space and reflection time, and so a library of extracted wavelets in the time–frequency domain was used for seismic inversion. Maps of the computed fracture fluid index and estimated fracture weaknesses were used to help to visualize the role of fractures in reservoir productivity, and revealed a consistency with the seismic peak frequency attribute in identifying zones of highly compliant fracture fill. The estimated fracture model demonstrates a good fit with the fractures seen in the available core samples and implies that the fracture fluid index is a useful attribute for determining the productive zones in the reservoir.

Our previous study published in 2023 examined the estimated ultimate recovery (EUR) of conventionally recoverable oil, gas and condensate in 1175 of the Earth's largest reservoirs in relation to reservoir temperature and showed that 74% occurs within the ‘Golden Zone’ (GZ) temperature range of 60–120 ± 2°C, with only 6% at higher temperatures. This present article examines the temperature distribution of EUR in 18 geographical regions not covered earlier, including six with EUR distributions skewed towards low temperatures and three with distributions skewed towards high temperatures. A fuller explanation is provided here as to why diagenetic processes are thought to be the main causes of overpressure in deeply buried reservoirs, and a new model is proposed for how the opening of the Arctic and North Atlantic oceans led to the uplift of Arctic continental margins, with possible negative consequences for Arctic exploration potential. Particular attention is given to examples of large reservoirs at temperatures outside the GZ in order to examine the possible factors favouring these occurrences. Most low-temperature cases can be ascribed to tectonic uplift and cooling subsequent to petroleum accumulation, whereas most of the high-temperature reservoirs have low–moderate fluid pressure consistent with preservation of hydrocarbon columns due to open lateral drainage. It is clear that reservoir temperature is a useful parameter for exploration risk analysis but one that should be calibrated using available analogues relevant for each area of interest.

The main anticlines in the Axial Zone of the Eastern Cordillera are conspicuous geomorphic features that can be detected with remote sensing images and geological mapping. In this work, the anticlines that exhibit conspicuous double-plunging three- or four-way closures that are preferentially located in the region immediately north of Bogotá within the Axial Zone were first documented. The main structural style was then illustrated with balanced cross-sections. After this type of structure had been identified, 19 one-dimensional petroleum systems models were produced in the adjacent synclines to assess the timing of generation and migration of petroleum using optimistic source-rock parameters. Two different scenarios were modelled, one of them having an additional 900 m of deposited Paleogene sediments. Based on these models, maps for the transformation ratio and hydrocarbon expulsion from the main source rock (the Chipaque Formation) were created in order to assess the timing of the main generation and expulsion. This allowed us to document that the main phase of generation occurred between the Late Eocene and the Middle Miocene. Previous studies have supported the idea that the main structures had formed by the Late Oligocene–Early Miocene. Based on this, it was concluded that it would have been possible for gas and light crude oil accumulations to have formed at that time but there was the problem of their preservation. However, the modelling of petroleum generation in the updip sectors of the potential kitchens may suggest an undiscovered potential that has not previously been documented.

The petroleum system elements in the Komombo Basin have not yet been fully assessed. This study aims to evaluate source rocks, reservoirs and seals within the basin by integrating 2D seismic profiles and well logs together with geochemical, core and petrophysical data. Four source rocks are identified within the Cretaceous shale intervals of the B Member of the Six Hills, upper Maghrabi, Quseir and Dakhla formations. The quality of the B Member, upper Maghrabi and Quseir source rocks is good to very good, while the Dakhla Formation demonstrates good to excellent quality. Geochemical characteristics vary across the basin, with higher kerogen quality and thermal maturity observed in the depocentre compared to the flanks. Four reservoirs are recognized in the basin, including the A Member, C Member, sandstones within the D–G members of the Six Hills Formation, and the Sabaya and Maghrabi formations. The A Member reservoir demonstrates a moderate reservoir quality, while the C Member reservoir displays a fair quality. Numerous sandstones with 15–25% porosity values are observed within the D–G members. The Sabaya–Maghrabi reservoir generally exhibits good to very good quality, and is characterized by high porosity and varying permeability. Due to their high organic matter content, the Dakhla and Quseir formations show potential as unconventional reservoirs. Several shale units within the Komombo Basin serve as potential seal rocks. These include the B Member of the Six Hills, Abu Ballas, upper Maghrabi and Taref formations, as well as intra-formational shales within the reservoir rocks. Seismic interpretation indicates that faults are the predominant trapping mechanism in the basin.