Petroleum Potential Of Basins Research Articles

Introduction to this special section: Basin exploration

Originally, explorers relied on hydrocarbon seeps and 2D seismic lines to define a basin's petroleum potential and to identify its best part. Due to dramatic improvements in seismic technology, today's explorers have access to a vast seismic tool kit, from basin-scale regional 3D seismic surveys to neural network techniques that directly derive reservoir properties from seismic volumes. However, in frontier or mature exploration, geoscientists are often limited by the amount of well data and rock properties information available, and they may deal with poor(er) seismic that makes seismic calibration difficult. Successful explorers will require a lot of knowledge-based creativity to derive meaningful geologic and reservoir properties models to reduce exploration risk. By embracing uncertainties, explorers develop “outside-the-box” thinking to help them chase the hydrocarbon molecules and unlock the prize. With their knowledge in rock physics, subsurface deformation, and wave propagation, geoscientists are deploying new methodologies and tools to fill the data gap and produce an improved description of the subsurface.

The experience in estimating the sedimentary basin petroleum potential on the basis of study of mud volcanic breccia clasts (an Example from the Deep Part of the Gulf of Cadiz)

Mud volcanism is a natural phenomenon well-known for on-shore and off-shore environments. Its major driving forces are deeply seated fluid accumulations and lithology and tectonism favorable for creating overpressure within deep strata with subsequent breakthrough of solid, liquid, and gaseous products of mud volcanism towards a ground surface. The mud breccia clasts provide information about the sedimentary section (up to several kilometers thick) through which the mud volcano erupted. Geochemical investigation of mud breccia clasts with characteristics of source rocks can help in understanding the petroleum potential of entire basin prior to expensive offshore exploration drilling. This is an especially important and useful method for initial estimation of petroleum potential of deep continental margin basins. The method of geochemical investigation of organic matter in the mud breccia clasts allowed to identify the Miocene and Upper Cretaceous clayey and carbonate deposits in the sedimentary sequence in the deep part of the Gulf of Cadiz as having the highest petroleum potential.

Unconventional petroleum resource evaluation in Queensland

The search for unconventional petroleum resources requires a shift in the way the petroleum potential of sedimentary basins is assessed. Gas in source rocks and tight reservoirs has largely been ignored in preference for traditional conventional gas plays. Recent developments in technology now allow for the extraction of gas trapped in low-permeability reservoirs. Assessments of the unconventional petroleum potential of basins, including estimates of the potential resource are required to guide future exploration. The Geological Survey of Queensland is collaborating with Geoscience Australia (GA) and other state agencies to undertake regional assessments of several basins with potential for unconventional petroleum resources in Queensland. The United States Geological Survey methodology for assessment of continuous petroleum resources is being adopted to estimate total undiscovered oil and gas resources. Assessments are being undertaken to evaluate the potential of key formations as shale oil and gas and tight-gas plays. The assessments focus on mapping key attributes including depth, thickness, maturity, total organic carbon (TOC), porosity, gas content, reservoir pressure, mineralogy and regional facies patterns using data from stratigraphic bores and petroleum wells to determine play fairways or areas of greatest potential. More detailed formation evaluation is being undertaken for a regional framework of wells using conventional log suites and mudlogs to calculate porosity, TOC, maturity, oil and gas saturations, and gas composition. HyLoggerTM data is being used to determine its validity to estimate bulk mineralogy (clay-carbonate-quartz) compared with traditional x-ray diffraction methods. These methods are being applied to key formations with unconventional potential in the Georgina and Eromanga basins in Queensland.

The role of deep seismic reflection data in understanding the architecture and petroleum potential of Australia's onshore sedimentary basins

The onshore energy security program, funded by the Australian Government and conducted by Geoscience Australia, has acquired deep seismic reflection data across several frontier sedimentary basins to stimulate petroleum exploration in onshore Australia. Detailed interpretation of deep seismic reflection profiles from four onshore basins, focussing on overall basin geometry and internal sequence stratigraphy, will be presented here, with the aim of assessing the petroleum potential of the basins. At the southern end of the exposed part of the Mt Isa Province, northwest Queensland, a deep seismic line (06GA–M6) crosses the Burke River structural zone of the Georgina Basin. The basin here is >50 km wide, with a half graben geometry, and bounded in the west by a rift border fault. Given the overall architecture, this basin will be of interest for petroleum exploration. The Millungera Basin in northwest Queensland is completely covered by the thin Eromanga Basin and was unknown prior to being detected on two seismic lines (06GA–M4 and 06GA–M5) acquired in 2006. Following this, seismic line 07GA–IG1 imaged a 65 km wide section of the basin. The geometry of internal stratigraphic sequences and a post-depositional thrust margin indicate that the original succession was much thicker than preserved today and may have potential for a petroleum system. The Yathong Trough, in the southeast part of the Darling Basin in NSW, has been imaged in seismic line 08GA–RS2 and interpreted in detail using sequence stratigraphic principles, with several sequences being mapped. Previous studies indicate that the upper part of this basin consists of Devonian sedimentary rocks, with potential source rocks at depth. In eastern South Australia, seismic line 08GA–A1 crossed the Cambrian Arrowie Basin, which is underlain by a Neoproterozoic succession of the Adelaide Rift System. Stratigraphic sequences have been mapped and can be tied to recent drilling for mineral and geothermal exploration. Shallow drill holes from past petroleum exploration have aided the assessment of the petroleum potential of the Cambrian Hawker Group, which contains bitumen in the core, indicating the presence of source rocks in the basin system.

THE PETROLEUM SYSTEM IN THE SANDINO FOREARC BASIN, OFFSHORE WESTERN NICARAGUA

The underexplored Sandino Basin (Nicaragua Basin/Trough) is located within the forearc area of western Nicaragua and NW Costa Rica. Exploration activity since 2004 has focussed on the onshore sector of the basin, and has included the first drilling campaign for over 30 years. Recent 2D basin modelling of the offshore sector together with organic geochemical studies has attempted to reassess the basin's petroleum potential. Geochemical data from the deepest offshore well indicate that Middle Eocene to Lower Oligocene sediments of the Brito Formation, as well as Upper Oligocene to Lower Miocene sediments of the Masachapa Formation, may have source rock potential. A third and perhaps more significant potential source rock interval is associated with the Lower Cretaceous black shales of the Loma Chumico Formation, which has been studied in the adjacent forearc area in NW Costa Rica (Tempisque Basin) and is inferred to be present in the Sandino Basin.The thermal history of the forearc basin is controlled by the low basal heat flow (39 mW/m2). 2D modelling has shown that the Sandino Basin is thermally mature, resulting in the potential for hydrocarbon generation in organic‐rich intervals in the Brito and Masachapa Formations. A petroleum‐generating “kitchen” has tentatively been identified on a NE‐SW seismic section which crosses the basin. Modelling suggests that this kitchen has been active from the Late Eocene until the present day, and that the main phases of petroleum generation in general coincide with phases of maximum subsidence in the Late Eocene, Late Oligocene and Plio‐Pleistocene. Hydrocarbon migration most probably occurred from the deep basin towards the flanks. Significant volumes of petroleum may have been lost prior to the Late Miocene before the formation of a coastal flexure which can be recognised in the NE of the seismic profile.

サハリン南西部における非海成根源岩と炭化水素ポテンシャル

There exist coal-bearing Paleogene basins along the Straits of Tatar, in the southwest Sakhalin. Those are presumed to be the northward extension of the hydrocarbon-yielding Ishikari Basin. Several basins in the southwest Sakhalin yields matured source rocks, which are evident from the existence of the offshore Izyilmetiev gascondensate field and many oil seepages on land.Five Paleocene coals, one Miocene coal and four Miocene siliceous mudstones were collected for pyrolysis analysis in the southwest Sakhalin on the land area. The results are as follows;Eocene coal (Nizhne Due Fm.) : HI : 263-430 mg/g, TOC : 45.46-73.05%, Tmax : 408-424 degree C.Miocene coal (Verkhne Due Fm.) : HI : 177 mg/g, TOC : 62.48%, Tmax : 408 degree C.Miocene siliceous mudstone (Kurassi Fm.) : HI : 159-275 mg/g, TOC : 1.26-1.79%, Tmax : 396-411 degree C.According to the results, Paleogene coals have most promising potential to expel hydrocarbon and develop seepages to the surface.This paper reports not only the non-marine source rock potential but also the petroleum potential of basins in the southwest Sakhalin on the analogy of the Yufutsu Field in the Ishikari Basin of Japan.