Petroleum Geoscience - Volume 16, Issue 1, 2010

The West Baram Line separates NW Borneo's two petroleum systems. Oligocene sandstone and Lower Miocene carbonate reservoirs of the gas-prone Luconia system lie SW of that line. Northeast of the West Baram Line, the oil-rich Baram-Balabac Basin produces from Middle Miocene to Early Pliocene sandstones deposited in a foreland basin on the western side of the mountainous interior of Borneo. On the present-day shelf exploration efforts spanning nearly four decades have focused on the Champion and Baram deltas and associated extensional growth fault structures. Many of these structures have experienced youthful inversion owing to ongoing tectonic shortening. Recent discoveries prove this petroleum system extends into deep water beyond the modern shelf edge where an active fold-thrust belt has formed above autochthonous rifted continental crust of the Dangerous Grounds province in the South China Sea. New regional mapping (c. 100 000 km2) integrating seismic, borehole and gravity data shows that the Baram-Balabac Basin is segmented into four structural domains whose boundary zones trend NW-SE similar to the strike of the West Baram Line. Domain boundaries appear to control the position of the basin's palaeoshelf edges, turbidite depositional systems, major unconformities and the position of the basin's largest fields. These observations suggest that the domain boundaries are the expression of deep structures, probably within the underlying rifted continental crust. Two of the domain boundaries can be projected onshore to align with fault systems separating contrasting geological elements indicating they represent features of tectonic interest. The onshore geology of NW Borneo represents the early history of the Baram-Balabac Basin. The onshore geology is reviewed and new outcrop, biostratigraphic and palaeomagnetic data from Sabah are discussed in light of current models for the region's tectonic evolution. A hybrid model is proposed in which the Baram-Balabac Basin post-dates the Sarawak Orogeny. The Sarawak Orogeny, which appears to be more regionally extensive than previously believed, is attributed to Eocene to Early Oligocene collision of the Dangerous Grounds and Reed Bank with Sabah and Palawan. In the proposed model Oligo-Miocene subduction of oceanic crust under NW Borneo is minimal. The Sabah Orogeny and younger inversion events are related to underthrusting of the Dangerous Grounds driven by both the opening of the South China Sea and by NW-directed subduction beneath SE Sabah in the Semporna-Dent Peninsula. In this context the structural complexity of the Baram-Balabac foreland basin reflects the adjustment of deep crustal blocks to far-field tectonic stress.

The study area is located in the foreland and in the frontal part of the Zagros Range (Persian Gulf), which contains very large oil and gas fields. The data consist of two orthogonal sets of 2D seismic sections. Folds trending NNE–SSW and N–S (Arabian trend) and NW–SE (Zagros trend) are documented. These folds developed during two folding phases: an older Late Cretaceous phase and a younger Late Cenozoic one. Folds with N–S and NNE–SSW trends formed during the older phase. During the younger phase the older, deep-seated, NNE–SSW Arabian folds were reactivated and tightened. These folds affected beds younger than the Cretaceous, forming open folds with the Arabian trend. At the same time, other folds with the NW–SE Zagros trend developed and these have been active until recent. Some giant and super-giant oil and gas fields are found in broad Arabian-trending folds in the Zagros foreland. This paper demonstrates that the Arabian folds in the study area are due to folding during the Late Cretaceous and to additional folding during Late Cenozoic times.

The Molve Field is the most important gas-condensate reservoir in Croatia. This petroleum system is not typical for the Pannonian System, because it comprises several reservoir lithologies, relatively high structural closure and significant tectonic influence on the field's compartmentalization. Strike-slip extension in the Middle Miocene and younger Late Miocene and Pliocene tectonics formed the present-day tectonic setting. Reservoir stratigraphy includes four lithofacies (from Devonian to Neogene) with a unique gas-water contact. The lithologies encompass cataclased granite, gneiss, schists, quartzites, dolomites, limestones and grainstones. Source rocks were generated in lacustrine organic facies and migration occurred in the Late Miocene to Pliocene. Reservoir gas includes 4.5–15.7% C2+, but also non-hydrocarbon components.

Analysed porosity data were approximated with a normal-distribution curve in lithofacies I, II and III, making it possible to calculate mean and variance easily by descriptive statistics. Moreover, gas production and effective thicknesses generally can be linked through a linear trend. However, significant deviations in the expected increased production rate with regard to greater reservoir thickness are observed for particular wells. This is a result of locally abrupt changes in effective porosities and permeabilities, and the size of the drainage area along the main fault zones. These faults resulted in significant compartmentalization of the field. Furthermore, owing to significant facies variations, permeability and porosity gradually change, especially in the vertical direction.

Significant reserves of condensate (3 × 106 m3) and gas (43 500 × 106 m3) with a high recovery rate of 71% make this field significant for geological reservoir models. The well-established geological model for this field and its stable high pressure have maintained production rates at a present level of approximately 2900 m3 gas and 165 m3 condensate per day, thus providing a valuable example for other large heterogeneous reservoirs in the Pannonian Basin.

Gas hydrates are recognized as a massive source of fossil fuel that could be far in excess of conventional hydrocarbon resources. The evaluation of formations that contain gas hydrates is therefore receiving renewed emphasis through contemporary petrophysical technology. A key factor is the use of logging-while-drilling (LWD) to sense hydrate-bearing intervals before drilling-induced thermal invasion and thence hydrate dissociation take hold. Recent advances in LWD technology have brought most of the potentially diagnostic tools onto the drill string, so there is little disadvantage in not having a wireline database. Moreover, modern tools have a sharper spatial resolution and a greater capability for differential depths of investigation. Petrophysical models have to be capable of distinguishing hydrates from ice in permafrost regions: this complication does not exist in the subsea environment. In general, pristine hydrates are characterized by high resistivity, low sonic transit time, and low density, possibly in conjunction with gas shows from mud logs. High neutron porosity can also be diagnostic away from permafrost. Other tools with a role to play include dielectric logs, for distinguishing ice from methane hydrate; electrical imagers, for identifying laminated hydrate formations; and magnetic resonance logs, for contributing to estimates of hydrate volume by difference, because of hydrate invisibility to these tools. The mode of hydrate formation is especially important, because a hydrate-supported structure will not produce as well as a framework-supported structure due to pore collapse with dissociation. A proposed workflow for the petrophysical evaluation of gas hydrates is guided by field examples. This is set against the backdrop of a hydrate categorization scheme, which brings together the type mode of hydrate formation at the pore scale, the type class of hydrate occurrence at the reservoir zonal scale, and the resolvability of mesoscale hydrate-bearing layers by contemporary logging tools. Although the formation evaluation of gas hydrates remains largely semi-quantitative, current interests are driving towards data-driven interpretation protocols that target estimates of producibility. Indicators are provided as to how this objective might be best approached.

A petrographic and microthermometric study of fluid inclusions in Jurassic and Cretaceous sandstones from the Porcupine Basin, offshore Ireland was integrated with innovative fluorescence lifetime measurements of hydrocarbon-bearing fluid inclusions to determine the compositions of the fluids associated with diagenesis and post-diagenetic fluid migration and the extent of hydrocarbon and aqueous fluid migration pathways. Petrographic analyses indicate that Jurassic strata were the main fluid migration pathways for hydrocarbon fluids and that hydrocarbon migration occurred relatively late in the diagenetic history of these sandstones. UV fluorescence and fluorescence lifetime measurements have recognized at least two chemically distinct hydrocarbon groups (Types 1a and 1b) with dissimilar lifetime-wavelength (τ-λ) profiles, consistent with at least two petroleum charges derived from different sources. Primary aqueous inclusions in authigenic cements show that cementation in Cretaceous sandstones occurred at relatively shallow levels at low temperatures (<50°C), while inclusions in authigenic cements in Jurassic sandstones were trapped at higher temperatures (70–120°C) and deeper levels. Aqueous fluid inclusions in intergranular trails indicate that post-cementation fluid migration occurred at high temperatures (up to 175°C). These high temperature fluid migrations are interpreted to be associated with plume-related activity during the opening of the North Atlantic.

A well-known method to determine the hydrocarbon saturation distribution in a reservoir model is by using a saturation-height function derived from capillary pressure measured on core samples. This approach fails, however, in complex formations and does not use information from wireline logs. In this paper we use an artificial neural network to develop a saturation-height function for the complex Gharif Formation in Oman to predict the hydrocarbon saturation.

Different neural network models were developed using different input variables. The optimal model was able to generate the saturation-height function with an error of 0.046 (fraction of pore volume, PV) using wireline logs, including the logarithm of resistivity, cation exchange capacity and porosity. This is a considerable improvement over conventional methods based on capillary pressure. The neural network model was then used to predict the saturation in the formation as a function of depth, and robust results were obtained.