Petroleum Geoscience - Current Issue

Carbonaceous shales in the Southern Uplands-Down-Longford Terrane accretionary prism had extremely high potential for hydrocarbon generation in the Lower Paleozoic. Structural thickening in the prism enhanced the rapid generation of oil. Shale horizons are separated by thick turbidites composed of low-permeability greywackes, so oil under high fluid pressure either pooled along shale bedding surfaces or migrated into fractured greywackes. Pooled oil became solidified to bitumen, which locally formed deposits on a scale of tonnes, mined as coal. The carbon-rich shale also sequestered large amounts of sulfur from seawater, which precipitated as pyrite firstly during early diagenesis, then further during fluid flow through the shale beds. The oil was also sulfur-bearing. Deformation focused on the shale beds during the evolution of the accretionary prism would have been closely related to the fluid flow which precipitated bitumen and sulfides. The palaeo-fluids were also anomalously rich in methane and hydrogen, similar to fluids venting from modern accretionary prisms.

Supplementary material: details of localities searched for coal in Lower Palaeozoic, Southern Uplands-Down-Longford Terrane (locations shown in Fig. 6 ) are available at https://doi.org/10.6084/m9.figshare.c.6691597

Determining rock resistivity for saturation estimation in reservoirs is challenging due to the complex nature of pores in the rock. This paper aims to establish a computational relationship between formation factors (F) and permeability (K) by combining theoretical and experimental data. Firstly, the relationship between the permeability of the curved capillary model and formation factors, as well as the relationship between the permeability of the complex curved capillary model and formation factors, are deduced. Theoretical analysis proved that the formation factors (F) have a power relationship with permeability (K) and porosity ( ), and confirms the existence of additional resistivity (Rx ). To validate the theoretical study, we conducted a model analysis using open experimental data from 35 sandstone cores with different porosities and permeabilities from the tight gas sandstone in the Western US basins, which measured resistivity data in saline at 20, 40 and 80 Kppm, respectively. We confirmed the existences of additional resistivity (Rx ) by fitting the relationship between the rock resistivity of saturated formation water (R 0) and the formation water resistivity (R w). We then fitted the formation resistivity change factor (F d) with permeability (K), the formation resistivity change factor (F d) with porosity ( ), the additional resistivity (Rx ) with permeability (K), and the additional resistivity (Rx ) with porosity ( ). Both the changeable formation resistivity change factor (F d) and additional resistivity (Rx ) showed a strong linear relationship with permeability (K) in logarithmic coordinates.

We also verified the existence of a suitable equation using available experimental data by changing the formation parameters and permeability. The study shows that the fitting equations may be utilized to determine the changeable formation resistivity change factor (F d), additional resistivity (Rx ) and the rock resistivity of saturated formation water (R 0) with varying permeability. The predicted rock resistivity of saturated formation water (R 0) strongly correlates with that measured in the laboratory, providing better precision for future reservoir evaluations using saturation estimations.

Time-lapse or 4D seismic data are important constraints in reservoir studies because they enable monitoring of saturation and pressure changes that result from hydrocarbon production. 4D seismic data have been quantitatively added, along with production data, in history matching or data assimilation procedures to reduce uncertainty and improve production forecasts. Before performing quantitative studies, it is important to ensure that the 4D seismic data are reliable, with minimal artefacts such as side-lobe effects that can disturb the identification of anomalies. In this work, we propose different ways of treating 4D seismic data in data assimilation for a real reservoir. Explicitly, we evaluated the impact on data assimilation results when considering different amounts of 4D information and three treatments to the identified artefacts. The treatments were: ignoring them, excluding them from data assimilation or defining no seismic changes at their locations. The results show that well and seismic matches are improved when 4D seismic data are assimilated, also improving the production predictions. Despite being a thin reservoir, assimilating two single-layer maps allowed us to predict relevant observed dynamic behaviour, such as the evolved gas trapped in the lower interval. Furthermore, when a treatment was applied to the artefacts, they produced better models than using a single two-layer map (with lower production errors and visually closer impedances to the observed data). Our recommendation is the assimilation of well and 4D seismic data, with the exclusion of unreliable information, for better life-cycle decisions.

The following chemostratigraphy study was completed on the Permo–Carboniferous Unayzah Group in Eastern Saudi Arabia. The aim of the study was to determine whether the technique could be used to identify formation and member boundaries on a subregional scale, with the area extending for c. 550 km in a NW–SE direction and 350 km NE–SW. A total of 30 375 core and cuttings samples were analysed from 225 wells using ICP (Inductively Coupled Plasma) and XRF (X-ray Fluorescence) instruments, with data acquired for 42–53 elements for each sample in the range Na-U in the periodic table. Of these, details of 14 wells are discussed in the present work.

Based on variations in Zr/Ti, Zr/U, Zr/Y, Y/U, U/Th, Gd/Zr, Nb/Yb and Nb/Th it is possible to identify a hierarchical order of one zone, four subzones and five divisions, these chemozones being correlative on a subregional scale. By comparing geochemical, biostratigraphic, sedimentological and wireline log data in selected reference wells, it was possible to relate chemozones to particular members of the Unayzah Group. The differences in geochemistry between these chemozones/members is largely explained by changes in provenance, though depositional environment may have exerted at least some influence.

Interpretation of seismic data over the southeastern flank of the Eratosthenes High shows nine principal seismic stratigraphic units overlying probable faulted basement. Among these are three superposed carbonate platforms that build a stratigraphy exceeding 3000 m. Regional comparisons suggest these range in age from Jurassic to Miocene.

The Jurassic carbonate platform exhibits a layered stratigraphy and aggradational deposition style over the whole study area. A Lower Cretaceous platform subsequently developed as a linear, aggrading bank and prograded as multiple high-frequency sequences for more than 40 km into the Eratosthenes High interior, isolating an intrashelf basin that remained connected to the Levant Basin by a narrow seaway. The Jurassic platform margin was a fault-controlled, scalloped escarpment, while the mid-Cretaceous platform was strongly influenced by linear, NW–SE-orientated, fault-controlled sags.

The Miocene platform, a shoaling, ‘catch-up’ neritic shelf, was established after a hiatus during which the flat top of the Cretaceous platform lay below the photic zone. The Miocene platform surface was subsequently incised by Messinian erosional channels that fed offlapping and downstepping regressive carbonate or evaporitic shorelines which tracked Messinian sea-level fall. Updoming and segmentation of the Eratosthenes High occurred during the early Messinian prior to the emplacement of Messinian salt onto its flanks.

Assessing fault zones as fluid-migration pathways requires the characterization of permeability both across and along faults, as well as the adjacent volume. The hydraulic properties of the Vette Fault Zone, North Sea, are described by modelling the mixing of host-rock lithologies into the fault zone, and the fault width is derived from empirical relationships as a function of throw and clay content. To better understand the sensitivity related to the uncertainties in overburden lithologies and fault-width correlations, a parametric study with 1125 model realizations were solved in a 2D steady-state, single-phase, subsurface flow model. The fault zone, included as a discrete permeable structure, significantly alters the flow field compared to a model that only considers lithological juxtaposition. The most prominent hydraulic communication in the Vette Fault Zone is downwards from the storage reservoir where sand is mixed into the fault zone. Increasing the host-rock permeability in the overburden also increases the fault permeability and shifts the inflection point for down-fault flow, causing the pressurized reservoir to drain towards the overburden and the top surface. For CO2 storage application, the models highlighted the potential for downward communication along the fault for brine, and the CO2 capillary sealing towards the overburden.

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