Frontier Basins Research Articles

Bathymetry sediment thickness and crustal structure from satellite gravity data

Analysis of satellite gravity data offers an opportunity to rapidly evaluate the sedimentary structure of frontier basins. The accurate and evenly distributed measurements of the gravity field determined from satellite orbits contain information about the bathymetry, sediment thickness and crustal structure of the world’s oceans. These data have been used by various authors, e.g., Smith and Sandwell (1994), to predict bathymetry for ocean basins where sediment cover is thin and where crustal structure is well known. In these areas, over a short wavelength band (15-160 km), the gravity field is highly correlated with the bathymetry. Along continental margins, however, the gravity field is complicated by sedimentary basins and changes in crustal structure.The method presented here differs from previous techniques for analysis of satellite gravity data by inverting simultaneously for water, sediment and crustal thickness instead of decomposing spectral bands in the gravity field. The inversion is constrained by interpretations of seismic and other data, and by assumptions about the nature and spatial variability of the interfaces. The seabed, basement and crust/mantle boundaries are defined by a series of triangular facets, whose size varies as the amount of constraining data changes. The sediment/basement boundary and the base of the crust are defined by larger facets than those defining the bathymetry. Conditioning equations smooth the interfaces, make the depths tend towards the input values and ensure that the interfaces do not intersect. In areas of sparse bathymetric and crustal structural control a degree of ambiguity between longwavelength shallow structures and short-wavelength deeper features inevitably remains.This technique has been used to identify the presence and location of several sedimentary basins in an area 1250 by 1000 km west of New Zealand.

ABSTRACT: Natural fracture plays in an early Palaeozoic Frontier (Eastern Warburton) Basin, South Australia

ABSTRACT: Natural fracture plays in an early Palaeozoic Frontier (Eastern Warburton) Basin, South Australia

ABSTRACT: Deep-water frontier basins of northwestern New Zealand - burial history and hydrocarbon maturation

ABSTRACT: Deep-water frontier basins of northwestern New Zealand - burial history and hydrocarbon maturation

ABSTRACT: Offshore frontier basins of southern New Zealand

ABSTRACT: Offshore frontier basins of southern New Zealand

Predicting Porosity through Simulating Sandstone Compaction and Quartz Cementation

Presently available techniques for predicting quantitative reservoir quality typically are limited in applicability to specific geographic areas or lithostratigraphic units, or require input data that are poorly constrained or difficult to obtain. We have developed a forward numerical model (Exemplar) of compaction and quartz cementation to provide a general method suited for porosity prediction of quartzose and ductile grain-rich sandstones in mature and frontier basins. The model provides accurate predictions for many quartz-rich sandstones using generally available geologic data as input. Model predictions can be directly compared to routinely available data, and can be used in risk analysis through incorporating parameter optimization and Monte Carlo techniques. The diagenetic history is modeled from the time of deposition to present. Compaction is modeled by an exponential decrease in intergranular volume as a function of effective stress. The model is consistent with compaction arising from grain rearrangement, ductile grain deformation, and brittle failure of grains, and accounts for the effects of fluid overpressures and stable grain packing configurations. Quartz cementation is modeled as a precipitation-rate-controlled process according to the method of Walderhaug (1994, 1996) and Walderhaug et al. (in press). Input data required for a simulation include effective stress and temperature histories, together with the composition and texture of the modeled sandstone upon deposition. Burial history data can be obtained from basin models, whereas sandstone composition and texture are derived from point-count analysis of analog thin sections. Exemplar predictions are consistent with measured porosity, intergranular volume, and quartz cement fractions for modeled examples from the Quaternary and Tertiary of the Gulf of Mexico Basin, the Jurassic of the Norwegian shelf, the Ordovician of the Illinois basin, and the Cambrian of the Baltic region.

The regional geology and exploration potential of the NE Rockall Basin

The Northeast Rockall Basin lies 130 km to the NW of the Outer Hebrides and to the immediate SW of the Faeroe–Shetland Basin. It is a frontier basin by virtue of minimal well and seismic control, combined with problems created by a thick Lower Tertiary basalt cover. A regional geological evaluation of the area has therefore proved critical in developing a good understanding of the basin. Gravity and magnetic modelling along key seismic lines suggest that over 6000 m of pre-Tertiary section may be accommodated in the NE Rockall Basin and has revealed a number of important structural elements. In particular, the presence of NNE–SSW trending structural elements infers a Jurassic age to some of the rifting on the grounds that other major rifts of this trend were active at this time. BGS shallow boreholes have encountered Mesozoic sediments (including Kimmeridge Clay facies) on the Outer Hebrides Platform to the east. It is likely that similar sediments will occur within the NE Rockall Basin. Migrant oil in the study area has an affinity with a Kimmeridge Clay Formation source rock. The presence of a Lower Jurassic source rock is also possible. The Kimmeridge Clay Formation has been modelled to reach a thickness of over 250 m in the centre of the basin. It is predicted to lie currently within the oil generation window over a large portion of the basin, with the top of the oil window occurring at a depth of approximately 3750 m. Modelling predicts that approximately 75 billion barrels of oil equivalent have been generated during Paleocene to Recent times. Gas generation is predicted to be minimal and localized. The NE Rockall Basin and the Faeroe–Shetland Basin have been affected by the same Tertiary tectonic, thermal and igneous events. A regional Tertiary sequence stratigraphic framework has been established and correlated with a scheme created for the Faeroe–Shetland Basin. Lower Tertiary basin-floor fans are anticipated to form an important exploration target. In addition, prospectivity generated by footwall-derived fan-deltas developed along the margin of the NE Rockall Basin has been recognized. The delineation of Mesozoic prospects in the NE Rockall Basin must await the acquisition of additional seismic data and the interpretation of early drilling results. However, all the play elements required to generate Mesozoic prospectivity are currently thought to be present.

West Greenland versus Vøring Basin: comparison of two deepwater frontier exploration plays

Two new frontier exploration areas were opened during 1996 in deepwater areas of the Northern Atlantic, the Fylla area (Davis Strait, offshore West Greenland) and the Vøring Basin (Norwegian Sea). Both are part of the North Atlantic rift system but have different rift histories. The Labrador Sea–Davis Strait probably did not begin to rift until Early Cretaceous times: Cretaceous sediments most likely rest on Ordovician carbonates or Precambrian basement. The Norwegian Sea area has experienced episodic rifting since Palaeozoic time and much of the area has Jurassic source and reservoir rocks. Jurassic rocks remain unproven in the Vøring Basin, because Cretaceous deposits are very thick in most of that area. Both rifts culminated with volcanism and seafloor spreading beginning in the Paleocene. Although the two areas have different rift histories, they share many common geological characteristics which influence their petroleum prospectivity. Exploration plays in both areas rely primarily on unproven Cretaceous source rocks. Jurassic rocks are probably absent across the Davis Strait area and, if present, are overmature across much of the Vøring Basin. Both basins have seismic evidence that hydrocarbons may be present, however. The Fylla area has seismic flat spots on at least four separate fault blocks. Direct hydrocarbon indicators (DHI) in the Vøring Basin include the well-known seismic flat spots and amplitude anomalies on several fault blocks of the western Nyk High. The chance for oil is high-risk in both areas, because the organic quality of the possible source rocks is unknown. Oil seeps (Davis Strait) and traces of oil shows (Vøring Basin) suggest that oil may be present. Immaturity is a concern for potential source rocks in the Fylla area, but overmaturity into the gas window is a risk for much of the Vøring Basin. Reservoir rocks are also anticipated to be of Cretaceous age. Cretaceous sandstones are common in Canadian wells in the Labrador Sea and in outcrops in West Greenland, where they are mostly continental to deltaic. Cretaceous sandstones have not yet been found in offshore West Greenland wells, but equivalent sandstones may be more distal and turbiditic in the offshore Fylla area. Cretaceous sandstones had been found in a scattering of wells in the Norwegian Sea and their presence in much of the central Vøring Basin was suggested by a prominent high-amplitude seismic package. The 6707/10-1 well found excellent reservoir-quality Upper Cretaceous turbidite sands on the Nyk High in the Vøring Basin. Paleocene sediments appear to be mostly shale-prone in both areas, although coarse Paleocene sandstones crop out in West Greenland. Both exploration areas offer huge structures which could hold world-class hydrocarbon deposits, yet carry high exploration risk for oil. No wells had been drilled in the Fylla licence as of 1998, but a late 1997 well discovered gas on one of the Vøring Basin fault blocks. These two exploration areas still offer exciting potential for significant future discoveries. In addition, data are sparse in these frontier basins, thus workers of each area may benefit by learning about the other basin.

Abstract: Hydrocarbon Potential of the St. Lawrence Lowlands of Northern New York: A Frontier Basin Investigation 

Abstract: Hydrocarbon Potential of the St. Lawrence Lowlands of Northern New York: A Frontier Basin Investigation 

The integration of seismic interpretations with gravity and magnetic 2-D modeling — An example from the offshore Faroes area

The Faroe‐Shetland Basin, on the Northwest European Atlantic Margin, is one of the last frontier basins in the area (Figure 1). In recent years, the basin’s southeastern flank, which lies in U.K. waters, has attracted much attention primarily because of the Foinaven and Schiehallion Paleocene oil discoveries that have an estimated 500 and 350 million bls of reserves, respectively. The northwestern flank of the basin, which lies in Faroese waters, has remained a totally unexplored area. This is partially due to the presence of an unknown thickness of basalt that covers the islands and the offshore area.

Comparative Study of the Mature Basin of the Bohai Bay and New Frontier Basins of the Mongolian Plateau, China  :ABSTRACT

Comparative Study of the Mature Basin of the Bohai Bay and New Frontier Basins of the Mongolian Plateau, China  :ABSTRACT

BASEMENT CONTROL ON THE DEVELOPMENT OF EXTENSIONAL SYSTEMS IN AUSTRALIA'S TIMOR SEA: AN EXAMPLE OF HYBRID HARD LINKED/SOFT LINKED FAULTING?

A series of rift models has been developed for basin systems in Australia's Timor Sea, via the interpretation of newly acquired deep crustal seismic and high resolution aeromagnetic data. These models, which incorporate observations on rift architecture, fault geometries, fault orientation, basement grain and composition, extensional transport direction and reactivation history, have then been iteratively tested by sophisticated analogue modelling experiments. This work has led to the development of a hybrid hard linked/soft linked (basement-involved/basement-detached) fault model. In this model, basement grain is the principal control on the rift architecture that develops, with pre-existing fracture systems acting to establish discrete offsets (hard linkages) between adjacent extensional faults. It is these basement features that produce the recti-linear features which are so common in aeromagnetic data around the Australian margin. With progressively greater extension, the basement-involved, hard linked system exerts no through-going (transfer fault-type) influence over the faulting within the overlying syn-rift phase, with the linkages between the syn-rift faults being 'soft' (via relay ramps, etc). However, as the hard links do act to relay the extensional faults or to flip their polarity (thereby typically producing cross-basinal highs), hard links strongly segment the extensional system into compartments of similar extensional style, and do control the relative positions of source rocks, fluid migration pathways and reservoirs within the rift. During basin reactivation (particularly inversion), the location and geometry of the underpinning, hard linked basement features closely control the locations of the traps that develop in the syn-and post-rift section, and the late-stage fluid flow history. When combined with aeromagnetic data, which define the location of the under-pinning, recti-linear, hard linked basement features, and some regional seismic data, these observations provide a first-pass predictive tool for determining where source depocentres, reservoirs and major structures are likely to be developed in a frontier basin, or where more subtle structural and/or stratigraphic traps might be found in a mature province.

Integrated Analysis of High Resolution Aeromagnetic And Satellite Imagery Data for Hydrocarbon Exploration in Frontier and Mature Basins: ABSTRACT

Integrated Analysis of High Resolution Aeromagnetic And Satellite Imagery Data for Hydrocarbon Exploration in Frontier and Mature Basins: ABSTRACT

The Geological Survey of Canada: Energy Needs of Tomorrow Through Collaboration Today: ABSTRACT

Canada`s national centre for geoscience research and information is the Geological Survey of Canada (GSC). Two of its divisions, the Institute of Sedimentary and Petroleum Geology and the Atlantic Geoscience Centre work closely with the energy exploration and production industry and universities. One successful GSC innovation is the Industrial Farmers Program that promotes cost-shared projects on geoscience problems of mutual interest. An example is the Hydrocarbon Charge Modelling Project which has struck a series of mutually beneficial alliances among the GSC, oil and gas companies and universities. The GSC`s high quality skills in basin analysis, including sequence stratigraphy, biostratigraphy, structure and tectonics, petroleum geology, geophysics, geochemistry and environmental work are underpinned by vast data holdings on Canada`s mature Western Canada Sedimentary Basin and onshore/offshore frontier basins. Laboratory facilities include laser ablation ICP-mass spectrometry, gas chromatography-mass spectrometry, Rock-Eval/TOC, pyrolysis and thermal analysis, X-ray diffraction and fluorescence, scanning electron microscopy, organic and inorganic petrology and paleontology processing. Sophisticated computing facilities provide capabilities in basin and crustal modelling, 2- and 3-D seismic interpretation and seismic processing and computerised cartography. Solutions to the exploration, production and environmental problems faced by a cyclical business sector are mom efficiently sought through cooperative research by bringing togethermore » the diverse capabilities of industry, government and universities. Through such broad, collaborative partnerships society will ensure the economic and environmentally sustainable development of its future energy needs.« less

Approaches to Predicting Reservoir Quality in Sandstones

Despite limited understanding of the details of many diagenetic processes, empirical techniques can be used effectively to predict reservoir quality prior to drilling. The predictive approach depends mainly on the availability of empirical data in the area of interest. In frontier basins, mean or maximum porosity of a potential sandstone reservoir can be estimated for a given composition and level of thermal exposure (or burial depth). The reliability of the estimates is constrained by input data. Approximate values of input parameters can be obtained from seismic data in combination with geological analysis of the area. In basins with sufficient information to generate calibration data sets, the predictive technique uses regression analysis. The applicability of this approach is constrained by the limits imposed by the calibration data set and is generally limited to samples containing less than 10% pore-filling cement. Quartz-rich sandstones (>85% framework quartz), cemented with quartz, are an exception to the 10% limit because quartz cementation commonly is related to burial history and rock texture. In weakly cemented sandstones, the critical variables controlling porosity are detrital composition, sorting, and burial history. Permeability can be predicted independently of porosity using the same variables plus grain size. These variables can be evaluated from seismic data and facies models. T is approach is best suited either for sandstones in which compaction is the main porosity-reducing process or for quartz-rich sandstones. An adequate predictive model for sandstone suites with a wide range of cement content can be obtained by dividing the calibration data set into two or more subsets and developing a predictive model for each. For example, one subset can be limited to samples with less than 10% cement, whereas the second subset will consist of samples with more than 10% nonquartz cement. Porosity and permeability in the first subset are then expressed by linear regression, whereas controls on reservoir quality in the more heavily cemented sandstones are determined independently based on understanding of cement distribution patterns.

Estimating number and field size distribution in frontier sedimentary basins using a Pareto model

Estimating the number of deposits likely to be found and their size distribution is important in exploration planning. In a frontier basin the geologic information for conducting a resource assessment is mostly limited to the regional level. Some methods, such as the play analysis approach (Crovelli and Balay, 1986) and the conceptual play model (Lee and Wang, 1983), can be used in conceptual plays or frontier basins, but these methods require the knowledge of the number of prospects, pool data characterizing the conditional field size distribution, and information documenting the exploration risk. For unexplored sedimentary basins, such as those in southern Africa, there are neither sufficient data covering reservoir volumetric parameters nor a number of mapped prospects that can be used to conduct such an assessment. In such a case a volumetric method using geologic analogy is applicable, by which a point estimate of hydrocarbon potential can be estimated, but this estimate provides no information on the likely size distribution. As a complement to the volumetric method, we discuss how to use the empirical Pareto law for estimating the number of fields and their size distribution in such a frontier region.

Unconformities and Porosity Development in Carbonate Strata: Ideas from a Hedberg Conference

The purpose of this paper is to highlight ideas from a Hedberg Conference concerning detection of unconformities and associated porosity in carbonate strata. Many types of information, including cores and outcrops, seismic data, eustatic sea level curves, wireline logs, biostratigraphic data, stable isotope trends, cycle stacking patterns, and tectonic and basin evolution models, can be used to predict and/or detect subaerial unconformities. All methods of detecting subaerial exposure with these types of information have limits and pitfalls. Detailed analysis of the stratigraphy, sedimentology, and diagenetic history of a rock sequence from outcrop or core data is considered the most reliable means of detecting subaerial exposure, though an integrated approach using all a ailable information is recommended. The relationship between subaerial exposure and subsurface porosity in carbonates is not simple or easily predicted. Subsurface porosity is the product of many factors operating during deposition, subaerial exposure, and burial. Several concepts should be recognized when evaluating porosity associated with subaerial unconformities. (1) Carbonate diagenesis during subaerial exposure rearranges pore networks, but usually does not increase the total porosity. Near-surface dissolution can simply lower a topographic surface without increasing porosity within the host limestone. In many cases, total porosity in carbonates under unconformities is actually reduced during subaerial exposure. (2) Permeability is likely to change more than porosity during subaerial exposure, increasing in some c ses but decreasing in others. (3) Pore systems evolve with time during subaerial exposure. Short periods of subaerial exposure (10,000-400,000 yr) are often associated with greater porosity than long intervals of subaerial exposure (1-20 million yr). Prolonged subaerial exposure may change permeability less than porosity because high-permeability, karst-related conduits can form quickly and persist for millions of years. (4) Many carbonates subjected to subaerial exposure have little or no porosity in the deep subsurface because compaction, cementation, and stratal collapse reduce porosity during burial. (5) Unconformity-related diagenesis may enhance reservoir potential by creating pore systems that are resistant to compaction during deeper burial. (6) Vugs, caverns, and breccias can fo m in the deep subsurface because of dissolution by basinal fluids independent of subaerial exposure. (7) Lithologic changes at unconformities, like shales overlying carbonates, can influence the flow of subsurface fluids during End_Page 857------------------------------ deeper burial, resulting in deep-burial dissolution localized along unconformities. If subaerial exposure and exposure surfaces are integrated into a sequence stratigraphic, paleogeographic, and climatic framework, systematic and hopefully predictable patterns will emerge. However, we do not fully understand the complex interplay between the factors critical to creating and preserving porosity in carbonates. Additional research is needed to quantify critical processes and products so we can reliably predict porosity associated with subaerial exposure during exploration in frontier basins, and on a smaller scale, during reservoir analysis.

BASIN RICHNESS AND SOURCE ROCK DISRUPTION — A FUNDAMENTAL RELATIONSHIP?

Primary petroleum migration (expulsion from source rocks) remains the least understood parameter controlling the genesis of oil deposits. In spite of this lack of understanding, many petroleum geochemists (including this Author) have previously considered expulsion from organic‐rich, mature source rocks to be very efficient. This viewpoint results from Rock‐Eval analyses of organic‐rich source rocks, analyses which demonstrate a loss of hydrocarbon (HC) generation capacity, by significant reduction in Rock‐Eval hydrogen indices, as such rocks are progressively buried in sedimentary basins. However, this progressive loss of HC generation capacity is not matched by numerically‐equivalent increases either in Soxhlet‐extractable HCs or the Rock‐Eval S1 pyrolysis peak. Thus, we conclude that almost all generated HCs have migrated from the source rocks.Notwithstanding, the petroleum geochemistry of the Williston Basin (North America) and other considerations strongly suggest that this logic may be flawed. Instead, it appears that most generated HCs may not migrate far from their generation site, but instead are lost before source‐rock samples arrive at the laboratory for analysis. This loss occurs from a HC‐gas volume expansion, which results from the large pressure decreases in rock chips or cores during the trip up the wellbore in the course of drilling operations. The large volume expansions of these HC gases, which are cogenerated and coexist with oil in the source rocks, literally blow most generated oil in source rocks into the drilling mud during the trip uphole.If most generated HCs do in fact remain in or near their source rocks, then it can be hypothesised that source rocks must be physically disrupted before meaningful expulsion can occur. Faulting, with accompanying significant fracturing, would appear to be the optimum naturally‐occurring process for physical disruption of source rocks. If these hypotheses are valid. intensity of faulting in deeply‐buried HC “kitchens” containing mature source rocks should strongly correlate with increasing basin richness, as defined by recoverable oil divided by basin‐sediment area or volume.This possible relationship is examined in this Paper; and there is a strong correlation of increasing basin richness with increasing structural intensity over and adjacent to basin depocentres. This correlation thus supports the hypothesis that physical disruption of mature source rocks is a necessary, and previously unappreciated, controlling parameter for oil expulsion. If a relationship between physical disruption of source rocks and oil expulsion indeed exists, then significant implications would follow for:(1) basin resource assessment;(2) conventional oil exploration in frontier basins; and(3) the probable existence of very large, previously unappreciated, oil‐resource bases in fractured, self‐sourced shales.

Relationships between seepage, tectonics and subsurface petroleum reserves

The relationship between visible petroleum seepage and commercial subsurface reserves has been investigated by a study of the distribution of documented seeps in south-east Asia. This is accompanied and integrated with a broader global study. The intensity of flowing seepage is controlled largely by present day tectonics and by the timing of petroleum migration. When such influences are reduced by isolating sets of tectonically similar basins, correlations are found between numbers of seeps and basin reserves. At a sub-basinal scale, seeps are observed to concentrate over tectonic features such as active diapirs, active faults and uplifted basin margins. It is relatively rare for seeps to directly overlie major fields, although many seeps may be linked to downdip accumulations by long tortuous paths. The best seep-accumulation relationships are observed in active compressional and diapiric settings, particularly those involving shallow reservoirs. Seeps are rare where traps are buried beneath thick undisturbed overburdens. The prime value of visible seeps in most frontier basins lies at the regional level, in the clues they give to the nature, extent and quantitative hydrocarbon potential of a basin's source system.

Remote Sensing and Image Processing for Exploration in Frontier Basins

A variety of remote sensing systems are available to explore the wide range of terrain in Central and South America and Mexico. The remote sensing data are recorded in digital form and must be computer-processed to produce images that are suitable for exploration. Landsat and SPOT images are available for most of the earth, but are restricted by cloud-cover. The broad terrain coverage recorded by Landsat thematic mapper (TM) is well suited for regional exploration. Color images are composited from various combinations of the 6 spectral bands to selectively enhance geologic features in different types of terrain. SPOT images may be acquired as stereo pairs which are valuable for structural interpretations. Radar is an active form of remote sensing that provides its own source of energy at wavelengths of centimeters which penetrate cloud-cover. Radar images are acquired at low depression angles to create shadows and highlights that enhance subtle geologic features. Satellite radar images of earth were recorded from two U.S. space shuttle missions in the 1980s and are currently recorded by the European Remote Sensing satellite and the Japanese Earth Resources Satellite. Mosaics of radar images acquired from aircraft are widely used in oil exploration, especially in cloud-covered regions.more » Typical images and computer processing method are illustrated with examples from various frontier basins.« less

Siliciclastic Sequence Stratigraphy and Petroleum Geology--Where to From Here?: GEOHORIZONS

Modern sequence stratigraphy has its roots in the development of seismic stratigraphy. In the late 1960s to middle 1970s, Peter R. Vail and his colleagues at Exxon Production Research Company developed stratigraphic techniques and principles based on time stratigraphic rather than rock stratigraphic (lithostratigraphic) relationships using multi-fold seismic reflection data. Seismic stratigraphic units called depositional sequences were recognized within which the strata seemed conformable and free of any internal stratal discontinuities. Based on global seismic stratigraphic observations, these workers inferred a eustatic signal and developed global sea level curves. Despite shortcomings, the sequence stratigraphic approach represents a powerful geological tool. At the field development scale, improved reservoir, source, and seal prediction can enhance petroleum recovery. At the exploration scale, this approach can be instrumental in developing new play concepts in both mature and frontier basins. To realize the full potential of this method, earlier conceptual models must be substantiated and modified. 80 refs., 2 tabs.