Petroleum Geoscience - Current Issue

Structural heterogeneities and tectonic forces in NE India give rise to changeable in situ stresses with varying orientations in this part of India. Wells located in the seismic gap in Upper Assam, the Naga Thrust and the Chittagong–Mizoram–Tripura fold belt of Mizoram are used to study stress state and borehole collapse models for the area. The absence of stress studies in the Mizoram area acts as an impetus to undertake stress studies. Poroelastic modelling shows the average ratio of maximum horizontal to vertical stress to be 0.79 for normal-faulted, 1.18 for thrust-faulted and 1.12 for strike-slip-faulted regimes. The S H direction varies from 193°N in Upper Assam to 213°N in Mizoram areas. The image log from a well in the Mizoram area shows the rotation of S H direction (c. 85°) to vary from 500 to 3707 m due to structural heterogeneity. The thrust and strike-slip regimes in the study area pose the major threat for safe borehole drilling in this complex terrain. To mitigate this issue, Mohr–Coulomb (MC) and Mogi–Coulomb (MG) rock failure criteria are discussed to predict the minimum mud weight required for borehole drilling. MG-predicted mud weight (MW) ensures borehole stability in wells in normal-faulted sediments, while MC-predicted MW prevents shear failure in wells in thrust and strike-slip regimes. A disc plot is used to model a stable wellbore drilling path with a minimum MW. A vertical well is shown to be stable in a normal-faulted regime, whereas horizontal drilling is preferable in the fold–thrust belt. Sensitivity analysis of geomechanical input parameters on MW using Monte Carlo simulation shows that S H has the maximum effect on MW regardless of the faulting regimes.

Many basins in Indonesia such as the North Sumatra, South Sumatra and Lower Kutai are highly overpressured. As a result, some wells have experienced drilling problems resulting in termination. In the literature, an empirical relationship such as Eaton has historically often been used to interpret pore pressure. In this paper, we take an alternative approach, one based on deterministic models.

Herein, we use Bowers’ and Dutta's equations to calculate the contributions of loading and unloading to the overall overpressure. Due to the advantages of the density log, the contributions of loading and unloading can be discriminated. By applying these methods, we suggest that in the North Sumatra Basin, unloading is caused by clay diagenesis. In the others, gas generation is significant.

The analysis also reveals that the unloading parameter (U) in the North Sumatra and South Sumatra basins is different than that of U in the Lower Kutai Basin. This suggests that mudrock in the overpressure zone in the Sumatran basins is more elastic than that in the Lower Kutai Basin, which appears to be more plastic in behaviour.

Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure

This study developed a one-dimensional numerical model of sedimentation and compaction based on the equivalent isochrone framework to investigate the impact of creep on geopressure during burial. In this framework, the void ratio is a function of effective stress and strain rate; the change in void ratio is the same with each order of magnitude decrease in strain rate at a constant effective stress. We simulated lower void ratio and higher overpressure when creep was included compared to cases where no creep was present and void ratio is only a function of effective stress. Creep causes apparent overconsolidation. The apparent overconsolidation ratio is used to quantify the magnitude of creep; this is the vertical distance from the normal compression curve in a void ratio v. effective stress plot. The magnitude of creep depends on the loading rate, and increases with depth at sites with low sedimentation rates. These findings bridge the gap between laboratory and field observations on rock compression behaviours. For example, it provides one explanation why laboratory-derived compression curves have a higher void ratio at a given effective stress. In addition, it suggests under what conditions the rock will behave elastically.

Thematic collection: This article is part of the Geopressure collection available at: https://www.lyellcollection.org/cc/geopressure

Failure to find hydrocarbon prospects in the Solway Basin region has resulted in a lack of research into the local Sherwood Sandstone Group petrography, reservoir quality and depositional history compared to the analogous southern reservoirs in the EISB which will be utilized for carbon storage. A detailed petrographic study is presented which aims to understand if the Solway Firth could have similar utility. The Permo–Triassic Sherwood Sandstone Group is believed to be deposited in depocentres connected during the Early Triassic by the extensive ‘Budleighensis’ fluvial system. Here, the Solway and Carlisle basins are proposed as terminal sites for this endorheic system, with the Lower Triassic Annan Sandstone Formation ascribed to the distal region of a fluvial distributary zone and the overlying Kirklinton Sandstone Formation thought to mark a transition to a basinal zone, depositing aeolian sandstones and locally associated playa lake facies. Fluid inclusion, stable isotope burial history modelling and field observations have been used to assess the relative timing and importance of different diagenetic cements. Early diagenetic cements include grain-rimming haematite and patchy calcite cement, especially in the Annan Sandstone Formation. Later burial diagenesis sees further calcite cement, quartz overgrowths and, restricted to the Kirklinton Sandstone Formation, ferroan dolomite. Porosity and permeability show significant differences between fluvial Annan and aeolian Kirklinton facies associations. Despite the finer grain size, a reservoir with excellent porosity and permeability as well as no hydrocarbon charging or legacy hydrocarbon extraction is persevered, suggesting the Solway Basin could be a secure CO2 storage site.

This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series

Supplementary material: An overview of the primary and secondary data collected and utilised in this study, as well as raw data values are available at https://doi.org/10.6084/m9.figshare.c.5906677

This work presents a new open-source carbonate reservoir case study, the COSTA model, that uniquely considers significant uncertainties inherent to carbonate reservoirs, providing a far more challenging and realistic benchmarking test for a range of geo-energy applications. The COSTA field is large, with many wells and large associated volumes. The dataset embeds many interacting geological and petrophysical uncertainties in an ensemble of model concepts with realistic geological and model complexity levels and varying production profiles. The resulting number of different models and long run times creates a more demanding computational challenge than current benchmarking models.

The COSTA model takes inspiration from the shelf-to-basin geological setting of the Upper Kharaib Member (Early Cretaceous), one of the most prolific aggradational parasequence carbonate formations sets in the world. The dataset is based on 43 wells and the corresponding fully anonymised data from the northeastern part of the Rub Al Khali basin, a sub-basin of the wider Arabian Basin. Our model encapsulates the large-scale geological setting and reservoir heterogeneities found across the shelf-to-basin profile, into one single model, for geological modelling and reservoir simulation studies.

The result of this research is a semi-synthetic but geologically realistic suite of carbonate reservoir models that capture a wide range of geological, petrophysical, and geomodelling uncertainties and that can be history-matched against an undisclosed, synthetic ‘truth case’. The models and dataset are made available as open-source to analyse several issues related to testing new numerical algorithms for geological modelling, uncertainty quantification, reservoir simulation, history matching, optimization and machine learning.

Supplementary material: supplementary data associated with this article can be found in the data repository for the COSTA model available at https://doi.org/10.17861/6e36e28d-50d9-4e31-9790-18db4bce6e5d and supplementary material is available at https://doi.org/10.6084/m9.figshare.c.5823571

Mudrock compaction trends from the Rovuma Basin offshore Mozambique are compared with those of the Norwegian North Sea, the Gulf of Mexico and the Kutai Basin offshore Indonesia. The comparison reveals that burial rates and timing of rifting are the dominant causes for the differences observed. The compaction trend for the Rovuma Basin is broadly similar to the trends for the Kutai Basin and the Gulf of Mexico, but very different from those for the Norwegian North Sea data, which show higher porosity and shallower onset of overpressure than those from the other three basins. The relationships for seismic velocities as a function of depth show strong similarities between the Rovuma and Gulf of Mexico basins.

These comparisons are used to make a general assessment of the capillary sealing potential of Cretaceous mudrocks in the Rovuma Basin, using a mudstone permeability-prediction function and a method for mapping permeability to threshold pressure, allowing estimation of maximum column heights for CO2 and CH4, with uncertainty ranges. Predicted CO2 column heights are slightly less than the equivalent CH4 column heights. The observed CH4 column height at one of the wells is significantly lower than that predicted from mudstone permeability, which is probably due to other factors such as fracturing or gas migration out of the structure. The comparison indicates generally good capillary sealing potential for the Rovuma Basin Cretaceous shales and offers a general approach for assessing CO2 storage potential from hydrocarbon sealing datasets from multiple offshore basins.

This article is part of the Energy Geoscience Series available at https://www.lyellcollection.org/cc/energy-geoscience-series