Abstract A new sequence-stratigraphic framework is proposed for the Burgan and Mauddud formations (Albian) of Kuwait. This framework is based on the integration of core, well-log, and biostratigraphic data, as well as seismic interpretation from giant oil fields of Kuwait. The Lower Cretaceous Burgan and Mauddud formations form two third-order composite sequences, the older of which constitutes the lowstand, trans-gressive, and highstand sequence sets of the Burgan Formation. This composite sequence is subdivided into 14 high-frequency, depositional sequences that are characterized by tidal-influenced, marginal-marine deposits in northeast Kuwait that grade into fluvial-dominated, continental deposits to the southwest. The younger composite sequence consists of the lowstand sequence set of the uppermost Burgan Formation and transgressive and highstand sequence sets of the overlying Mauddud Formation. This composite sequence is sand prone and mud prone in southern and southwestern Kuwait and is carbonate prone in northern and northeastern Kuwait. The lowstand sequence set deposits of the Burgan Formation are subdivided into five high-frequency depositional sequences, which are composed of tidal-influenced, marginal-marine deposits in northeastern Kuwait that change facies to fluvial-dominated deposits in southwestern Kuwait. The transgressive and highstand sequence sets of the Mauddud Formation are subdivided into eight high-frequency, depositional sequences. The Mauddud transgressive sequence set displays a lateral change in lithology from limestone in northern Kuwait to siliciclastic deposits in southern and southwestern Kuwait. The traditional lithostratigraphic Burgan-Mauddud contact is time transgressive. The Mauddud highstand sequence set is carbonate prone and thins south- and southwestward because of depositional thinning. Significant postdepositional erosion occurs at the contact with the overlying Cenomanian Wara Shale. The proposed sequence-stratigraphic framework and the incorporation of a depositional facies scheme tied to the sequence-stratigraphic architecture allow for an improved prediction of reservoir and seal distribution, as well as reservoir quality away from well control.

Abstract The Grand Banks of Newfoundland is a broad continental shelf that extends 450 km into the North Atlantic Ocean. A sequence of Mesozoic rift-events and subsequent break-ups associated with the North Atlantic rift are recorded in a series of complex basins. From the onset of exploration in the 1960’s, regional exploration on the Grand Banks has been primarily focused on the Early Cretaceous Ben Nevis and Hibernia formations shallow marine sandstone reservoirs. This early phase of exploration resulted in the discovery of the Hibernia, White Rose, and Hebron fields in the southern Jeanne d’Arc Basin. Collectively, these fields contain approximately 2.5 billion barrels of oil resources. The Terra Nova Field in the southern Jeanne d’Arc basin is the exception to this Early Cretaceous play trend, producing from Late Jurassic braided fluvial reservoirs (Jeanne d’Arc Formation) and contains approximately 500 million barrels of oil resources. This presentation is focused on recognizing and delineating a now proven petroleum system in the North Flemish Pass basin.

ABSTRACT The northeastern Grand Banks of Newfoundland is underlain by the Jeanne d’Arc Basin and the Outer Ridge. To date, twelve significant hydrocarbon accumulations, including the giant Hibernia oil field, have been discovered in the basin and three have been discovered on the Outer Ridge. Some of these discoveries are in submarine fans. The submarine fans on the northeastern Grand Banks can be grouped into four categories based on their age: 1) Late Jurassic submarine fans, derived from highlands to the south, 2) Early Cretaceous submarine fans, related to progradation of deltas of the Hibernia Formation; 3) Late Cretaceous submarine fans, associated with a major clastic wedge that prograded from the western margin of the basin; 4) Early Tertiary basin floor fans and slope fans related to a major sea level lowstand. Hydrocarbons have been encountered in all four groups of submarine fans. With only about 10% of the potential recoverable oil in the basin discovered so far ( McAlpine 1990 ), they could provide promising drilling targets.

Abstract Remaining reserves of marketable crude oil and natural gas in Canada are more than 1.43 billion [10 9 ] m 3 (9 billion bbl) and 1.84 trillion [ 10 12 ] m 3 (65 trillion cubic feet [tcf]), respectively. These reserves enable current annual extraction rates of 127 million m 3 (800 million bbl) of oil and 170 billion m 3 (6 tcf) of natural gas, mainly from the mature Western Canada Sedimentary Basin. In the new millennium, expanded contributions to production capacity will come initially from the Mesozoic Jeanne d’Arc Basin (e.g., Hibernia and Terra Nova oil) offshore Newfoundland and from basins off Nova Scotia (e.g., Sable Island gas). In northern Alberta, additional investment in exploiting the Cretaceous oil sands will enhance the production of upgraded (synthetic) crude oil, bitumen, and heavy oil. Notwithstanding the technical and commercial challenges, predictions of remaining exploitable resources in accessible areas exceed 5.6 trillionm 3 (200 tcf) of gas and 16 billion m 3 (100 billion bbl) of bitumen. In addition to oil sands, tight gas, and coal-bed methane in the Western Canada Sedimentary Basin, significant undeveloped resources are known in the remote Canadian Arctic islands (Sverdrup Basin), the Labrador shelf (gas), and the Beaufort Basin (gas and oil). Many of these resources will remain “orphaned,” depending on environmental aspects, delivery costs, markets, and commodity prices. Current “stranded gas” in the Mackenzie Delta and the shallow offshore waters of the Beaufort Sea will be connected (via the Mackenzie Valley corridor) to the natural-gas pipeline grid serving Canadian and United States markets.Associated gas reserves (presently reinjected at Hibernia) in the Jeanne d’Arc Basin, if not connected to shore by pipeline, may be developed using either natural-gas-to-liquid conversion or compressed-gas transport technologies. Canada’s resource base is not in crisis, but the rate of conversion of the resource base to productive capacity cannot be as rapid as the resource potential might suggest.

Abstract Apetroleum system modeling (PSM) study was performed on the Jeanne d’Arc Basin, offshore eastern Canada, to study the constraints and reliability of the reconstruction of petroleum reservoir filling histories. Petroleum generation and phase behavior were analyzed using phase-predictive compositional kinetic models (PhaseKinetics) determined by pyrolysis of Egret Member source rock samples. Various additional calibration data (well, rock, and fluid data), such as porosity, permeability, temperature (bottom-hole temperature, apatite fission tracks, fluid inclusions), maturity (vitrinite reflectance), and petroleum properties, such as API, gas-oil ratio, formation volume factor, and saturation pressure were integrated into this model. Different charge scenarios were tested for the effects of open and closed faults in the carrier system to reconstruct the most likely migration pathways for the petroleum that is trapped in the Terra Nova (TN) oil field. The most probable filling history includes charge to the reservoir from a local kitchen and a second kitchen located between Hibernia and TN that was responsible for the long-range migration. In the model, the hydrocarbons migrate from this kitchen in the northwest part of the study area along pathways defined by closed transbasin faults from the north into the field. This new migration concept differs from the traditional explanation based on geochemical measurements only von der Dick et al., 1989 ), which infers that local generation was solely responsible for filling the TN field. The latter can be disproved based on a simple mass balance calculation.

ABSTRACT Petroleum industry 3-D seismic data over the Hibernia Oil field, offshore eastern Canada, allows high resolution imaging of a shelf indenting submarine canyon system of Paleocene age. This canyon provided a point source of sediments for a lowstand wedge and basin floor fans preserved elsewhere in the basin and together form a well preserved Lowstand Systems Tract. Now buried by up to 2 kilometres of sediment, the quality and resolution of coverage allows mapping, visualization, and interpretation of canyon morphology and the palco-shelf sedimentary environments. Morphological differences along the course of the canyon provide clues to the geological mechanisms that initiated and modified the feature. These include changes in hydrodynamic regimes, slumping, headward erosion, and fluvial incision. Although not drilled, the nature of the Canyon’s fill is indicated by significant positive seismic relief over a portion of its length. This is attributed to differential compaction implying relatively coarse sediment fill. Comparison with recent outer shelf and upper slope canyon systems such as studied in the Gulf of Mexico’s Mississippi, Lavaca, and Yoakum canyons reveal several similarities.