Hydrocarbon exploration beneath the shallow allochthonous salt canopy of the ultra-deepwater central Gulf of Mexico has encountered three thick, sand-rich, submarine fan successions that punctuate an otherwise relatively condensed and fine-grained basin center stratigraphy. These sand-rich fans are Late Paleocene, Early Miocene, and Middle Miocene in age and each coincide with periods of very high sediment flux and basin margin instability. They are the primary exploration targets in most ultra-deepwater fields, recent discoveries, and failed exploration tests.
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Prolific hydrocarbon discoveries in the subsalt, commonly known as the “presalt,” section of Brazil and the conjugate African margin have created a business imperative to predict reservoir quality in lacustrine carbonates. Geothermal convection is a style of groundwater flow known to occur in rift settings, which is capable of diagenetic modification of reservoir quality. We simulated variable density groundwater flow coupled with chemical reactions to evaluate the potential for diagenesis driven by convection in subsalt carbonates.
Rates of calcite diagenesis are critically controlled by temperature gradient and fluid flux following the principles of retrograde solubility. Simulations predict that convection could operate in rift carbonates prior to salt deposition, but with rates of dissolution in the reservoir interval only on the order of 0.01 vol. %/m.y., which is too low to significantly modify reservoir quality. The exception is around permeable fault zones and/or unconformities where flow is focused and dissolution rates are amplified to 1 to 10 vol. %/m.y. and could locally modify reservoir quality. After salt deposition, simulations also predict convection with a critical function for salt rugosity. The greatest potential for dissolution at rates of 0.1 to 1 vol. %/m.y. occurs where salt welds, overlying permeable carbonates thin to 500 m (1640 ft) or less. With tens of million years residence times feasible, convection under these conditions could locally result in reservoir sweet spots with porosity modification of 1% to 10% and potentially an order of magnitude or more in reservoir permeability. Integrating quantitative model–derived predictive diagenetic concepts with traditional subsurface data sets refines exploration to production scale risking of carbonate reservoir presence and quality.
The Upper Jurassic Arab Formation in the Arabian Peninsula, the most prolific oil-bearing interval of the world, is a succession of interbedded thick carbonates and evaporites that are defined stratigraphically upsection as the Arab-D, Arab-C, Arab-B, and Arab-A. The Arab-D reservoir is the main reservoir in Khurais field, one of the largest onshore oil fields of the Kingdom of Saudi Arabia.
In Khurais field, the Arab-D reservoir is composed of the overlying evaporitic Arab-D Member of the Arab Formation and the underlying upper part of the Jubaila Formation. It contains 11 lithofacies, listed from deepest to shallowest: (1) hardground-capped skeletal wackestone and lime mudstone; (2) intraclast floatstone and rudstone; (3) pelletal wackestone and packstone; (4) stromatoporoid wackestone, packstone, and floatstone; (5) Cladocoropsis wackestone, packstone, and floatstone; (6) Clypeina and Thaumatoporella wackestone and packstone; (7) peloidal packstone and grainstone; (8) ooid grainstone; (9) crypt-microbial laminites; (10) evaporites; and (11) stratigraphically reoccurring dolomite.
The Arab-D reservoir lithofacies succession represents shallowing-upward deposition, which, from deepest to shallowest, reflects the following depositional environments: offshore submarine turbidity fans (lithofacies 1 and 2); lower shoreface settings (lithofacies 3); stromatoporoid reef (lithofacies 4); lagoon (lithofacies 5 and 6); shallow subtidal settings (lithofacies 7 and 8); peritidal settings (lithofacies 9); and sabkhas and salinas (lithofacies 10). The depositional succession of the reservoir represents a prograding, shallow-marine, reef-rimmed carbonate shelf that was subjected to common storm abrasion, which triggered turbidites.
A three-dimensional seismic data set and published data from exploration wells were used to reconstruct the tectonostratigraphic evolution of the Mandal High area, southern North Sea, Norway. The Mandal High is an elongated southeast-northwest–trending horst. Three fault families in the Lower Permian sequence, inherited from the basement structural grain of Caledonian origin, are interpreted: (1) a north-northwest–south-southeast–striking fault family, (2) a northeast-southwest–striking fault family, and (3) a near east-west–striking fault family. In addition, an east-southeast–west-northwest–striking fault family (4) that formed during Late Jurassic rifting and was reverse reactivated in the Late Cretaceous is interpreted. We suggest that inversion occurred because of small dextral motion along fault family 1. A final fault family (5) displays various strike orientations and is associated with salt movements.
Seven chronostratigraphic sequences defined by well data and recognized on three-dimensional seismic data are interpreted and mapped: Early Permian rifting in a continental environment; Late Permian deposition of the Zechstein salt and flooding; Triassic continental rifting; uplift and erosion in the Middle Jurassic with deposition of shallow-marine and deltaic sediments; rifting and transgression in a deep-marine environment during the Late Jurassic; a post-rift phase in a marine environment during the Early Cretaceous; and flooding and deposition of the Chalk Group in the Late Cretaceous. An eighth sequence was interpreted—Paleogene–Neogene—but has not been studied in detail. This sequence is dominated by progradation from the east and basin subsidence. Well and seismic data over the Mandal High reveal that large parts of the high were subaerially exposed from Late Permian to Late Jurassic or Early Cretaceous, providing a local source of sediments for adjacent basins.
Similar to the Utsira High, where several large hydrocarbon discoveries have been recently seen, the Mandal High might consist of a set of petroleum plays, including fractured crystalline basement and shallow-marine systems along the flanks of the high, thereby opening up future exploration opportunities.
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Sparsely drilled Scotian Basin larger than Gulf of Mexico.
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The Niobrara Petroleum System of the U.S. Rocky Mountain Region is a major tight petroleum resource play.
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