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Sequence stratigraphy and coal cycles based on accommodation trends were investigated in the coal-bearing Lower Cretaceous Mannville Group in the Lloydminster heavy oil field, eastern Alberta. The study area is in a low accommodation setting on the cratonic margin of the Western Canada sedimentary basin. Geophysical log correlation of coal seams, shoreface facies, and the identification of incised valleys has produced a sequence-stratigraphic framework for petrographic data from 3 cored and 115 geophysical-logged wells. Maceral analysis, telovitrinite reflectance, and fluorescence measurements were taken from a total of 206 samples. Three terrestrial depositional environments were interpreted from the petrographic data: ombrotrophic mire coal, limnotelmatic mire coal, and carbonaceous shale horizons. Accommodation-based coal (wetting- and drying-upward) cycles represent trends in depositional environment shifts, and these cycles were used to investigate the development and preservation of the coal seams across the study area. The low-accommodation strata are characterized by a high-frequency occurrence of significant surfaces, coal seam splitting, paleosol, and incised-valley development. Three sequence boundary unconformities are identified in only 20 m (66 ft) of strata. Coal cycle correlations illustrate that each coal seam in this study area was not produced by a single peat-accumulation episode but as an amalgamation of a series of depositional events. Complex relations between the Cummings and Lloydminster coal seams are caused by the lateral fragmentation of strata resulting from the removal of sediment by subaerial erosion or periods of nondeposition. Syndepositional faulting of the underlying basement rock changed local accommodation space and increased the complexity of the coal cycle development. This study represents a low-accommodation example from a spectrum of stratigraphic studies that have been used to establish a terrestrial sequence-stratigraphic model. The frequency of changes in coal seam quality is an important control on methane distribution within coalbed methane reservoirs and resource calculations in coal mining. A depositional model based on the coal cycle correlations, as shown by this study, can provide coal quality prediction for coalbed methane exploration, reservoir completions, and coal mining.
This article reviews the mechanisms of shale gas storage and discusses the major risks or uncertainties for shale gas exploration in China. At a given temperature and pressure, the gas sorption capacities of organic-rich shales are primarily controlled by the organic matter richness but may be significantly influenced by the type and maturity of the organic matter, mineral composition (especially clay content), moisture content, pore volume and structure, resulting in different ratios of gas sorption capacity (GSC) to total organic carbon content for different shales. In laboratory experiments, the GSC of organic-rich shales increases with increasing pressure and decreases with increasing temperature. Under geologic conditions (assuming hydrostatic pressure gradient and constant thermal gradient), the GSC increases initially with depth due to the predominating effect of pressure, passes through a maximum, and then decreases because of the influence of increasing temperature at greater depth. This pattern of variation is quite similar to that observed for coals and is of great significance for understanding the changes in GSC of organic-rich shales over geologic time as a function of burial history. At an elevated temperature and pressure and with the presence of moisture, the gas sorption capacities of organic-rich shales are quite low. As a result, adsorption alone cannot protect sufficient gas for high-maturity organic-rich shales to be commercial gas reservoirs. Two models are proposed to predict the variation of GSC and total gas content over geologic time as a function of burial history. High contents of free gas in organic-rich shales can be preserved in relatively closed systems. Loss of free gas during postgeneration uplift and erosion may result in undersaturation (the total gas contents lower than the sorption capacity) and is the major risk for gas exploration in marine organic-rich shales in China.
Anomalously high porosities and permeabilities are commonly found in the fluvial channel sandstone facies of the Triassic Skagerrak Formation in the central North Sea at burial depths greater than 3200 m (10,499 ft), from which hydrocarbons are currently being produced. The aim of our study was to improve understanding of sandstone diagenesis in the Skagerrak Formation to help predict whether the facies with high porosity may be found at even greater depths. The Skagerrak sandstones comprise fine to medium-grained arkosic to lithic-arkosic arenites. We have used scanning electron microscopy, petrographic analysis, pressure history modeling, and core analysis to assess the timing of growth and origin of mineral cements, with generation, and the impact of high fluid pressure on reservoir quality. Our interpretation is that the anomalously high porosities in the Skagerrak sandstones were maintained by a history of overpressure generation and maintenance from the Late Triassic onward, in combination with early microquartz cementation and subsequent precipitation of robust chlorite grain coats. Increasing salinity of pore fluids during burial diagenesis led to pore-filling halite cements in sustained phreatic conditions. The halite pore-filling cements removed most of the remaining porosity and limited the precipitation of other diagenetic phases. Fluid flow associated with the migration of hydrocarbons during the Neogene is inferred to have dissolved the halite locally. Dissolution of halite cements in the channel sands has given rise to megapores and porosities of as much as 35% at current production depths.
The Heidrun field, located on the Halten Terrace of the mid-Norwegian continental shelf, was one of the first giant oil fields found in the Norwegian Sea. Traditional reservoir intervals in the Heidrun field lie within the Jurassic synrift sequence. Most Norwegian continental shelf fields have been producing from these Jurassic reservoirs for the past 30 yr. Production has since declined in these mature fields, but recently, exploration for new reservoirs has resurged in this region. The Jurassic rifted fault blocks form a narrow continental shelf in Norway, thereby greatly reducing the areal extent for exploration and development within existing fields. As the rift axis is approached farther offshore, these Jurassic reservoirs become very deep, too risky to drill, and uneconomical. This risk has prompted exploration in more recent years of the shallower Cretaceous, postrift stratigraphic succession. Cretaceous turbidites have been found in the Norwegian and North Seas, and the discovery of the Agat field in the Norwegian North Sea confirms the existence of a working petroleum system capable of charging Cretaceous reservoirs. These Cretaceous reservoirs were deposited as slope- and basin-floor fans within a series of underfilled rifted deeps along the Norwegian continental shelf and are thought to be sourced from the localized erosion of Jurassic rifted highs. We use three-dimensional seismic and well data to document the geomorphology of a deep-water, Lower Cretaceous wedge (Cromer Knoll Group) within the hanging wall of a rift-related half graben formed on the Halten Terrace offshore mid-Norway. Seismic attribute extractions taken within this Lower Cretaceous wedge reveal the presence of several lobate to elongated bodies that seem to cascade over fault-bounded terraces associated with rifted structures. These high-amplitude, elongated bodies are interpreted as deep-water sedimentary conduits that are time equivalent to the Cretaceous basin-floor fans in more distal parts of the basin to the west. These half-graben fills have the potential to contain high-quality Cretaceous sandstones that might represent a potential new reservoir interval within the Heidrun field.
The carbonate sequences that were deposited in the now exhumed Tethyan Ocean influence many aspects of our lives today, either by supplying the energy that warms our homes and the fuel that powers our cars or providing the stunning landscapes for both winter and summer vacations. They also represent some of the most intensely studied rock formations in the world and have provided geoscientists with a fascinating insight into the turbulent nature of 250 Million years of Earth’s history. By combining studies from the full range of geoscience disciplines this presentation will trace the development of these carbonate sequences from their initial formation on the margins of large ancient continental masses to their present day locations in and around the Greater Mediterranean and Near East region. The first order control on growth patterns and carbonate platform development by the regional plate-tectonic setting, underlying basin architecture and fluctuations in sea level will be illustrated. The organisms that contribute to sequence development will be revealed to be treasure troves of forensic information. Finally, these rock sequences will be shown to contain all the ingredients necessary to form and retain hydrocarbons and the manner in which major post-depositional tectonic events led to the formation of some of the largest hydrocarbon accumulations in the world will be demonstrated.
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As oil and gas exploration and production occur in deeper basins and more complex geologic settings, accurate characterization and modeling of reservoirs to improve estimated ultimate recovery (EUR) prediction, optimize well placement and maximize recovery become paramount. Existing technologies for reservoir characterization and modeling have proven inadequate for delivering detailed 3D predictions of reservoir architecture, connectivity and rock quality at scales that impact subsurface flow patterns and reservoir performance. Because of the gap between the geophysical and geologic data available (seismic, well logs, cores) and the data needed to model rock heterogeneities at the reservoir scale, constraints from external analog systems are needed. Existing stratigraphic concepts and deposition models are mostly empirical and seldom provide quantitative constraints on fine-scale reservoir heterogeneity. Current reservoir modeling tools are challenged to accurately replicate complex, nonstationary, rock heterogeneity patterns that control connectivity, such as shale layers that serve as flow baffles and barriers.
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