Diagenesis and origin of calcite cement in the Flemish Pass Basin sandstone reservoir (Upper Jurassic): Implications for porosity development

The Flemish Pass Basin is a deep-water basin located offshore on the continental passive margin of the Grand Banks, eastern Newfoundland, which is currently a hydrocarbon exploration target. The current study investigates the petrographic characteristics and origin of carbonate cements in the Ti-3 Member, a primary clastic reservoir interval of the Bodhrán Formation (Upper Jurassic) in the Flemish Pass Basin.The Ti-3 sandstones with average Q_86.0F_3.1R_10.9 contain various diagenetic minerals, including calcite, pyrite, quartz overgrowth, dolomite and siderite. Based on the volume of calcite cement, the investigated sandstones can be classified into (1) calcite-cemented intervals (>20% calcite), and (2) poorly calcite-cemented intervals (porous). Petrographic analysis shows that the dominant cement is intergranular poikilotopic (300–500 μm) calcite, which stared to form extensively at early diagenesis. The precipitation of calcite occured after feldspar leaching and was followed by corrosion of quartz grains. Intergranular calcite cement hosts all-liquid inclusions mainly in the crystal core, but rare primary two-phase (liquid and vapor) fluid inclusions in the rims ((with mean homogenization temperature (T_h) of 70.2 ± 4.9 °C and salinity estimates of 8.8 ± 1.2 eq. wt.% NaCl). The mean δ¹⁸O and δ¹³C isotopic compositions of the intergranular calcite are −8.3 ± 1.2‰, VPDB and −3.0 ± 1.3‰, VPDB, respectively; whereas, fracture-filling calcite has more depleted δ¹⁸O but similar δ¹³C values. The shale normalized rare earth element (REE_SN) patterns of calcite are generally parallel and exhibit slightly negative Ce anomalies and positive Eu anomalies. Fluid-inclusion gas ratios (CO₂/CH₄ and N₂/Ar) of calcite cement further confirms that diagenetic fluids originated from modified seawater. Combined evidence from petrographic, microthermometric and geochemical analyses suggest that (1) the intergranular calcite cement precipitated from diagenetic fluids of mixed marine and meteoric (riverine) waters in suboxic conditions; (2)the cement was sourced from the oxidation of organic matters and the dissolution of biogenic marine carbonates within sandstone beds or adjacent silty mudstones; and (3) the late phases of the intergranular and fracture-filling calcite cements were deposited from hot circulated basinal fluids.Calcite cementation acts as a main controlling factor on the reservoir quality in the Flemish Pass reservoir sandstones. Over 75% of initial porosity was lost due to the early calcite cementation. The development of secondary porosity (mostly enlarged, moldic pores) and throats by later calcite dissolution due to maturation of organic matters (e.g., hydrocarbon and coals), was the key process in improving the reservoir quality.     

Diagenesis of the palaeo-oil-water transition zone in a Lower Pennsylvanian carbonate reservoir: Constraints from cathodoluminescence microscopy,microthermometry, and isotope geochemistry

Oil-water transition zones in carbonate reservoirs represent important but rarely studied diagenetic environments that are now increasingly re-evaluated because of their potentially large effects on reservoir economics. Here, data from cathodoluminescence and fluorescence microscopy, isotope geochemistry, microthermometry, and X-ray tomography are combined to decipher the diagenetic history of a 5-m-long core interval comprising the oil-water transition zone in a Lower Pennsylvanian carbonate reservoir. The aim is to document the cementation dynamics prior, during, and after oil emplacement in its context of changing fluid parameters. Intergrain porosity mean values of 7% are present in the upper two sub-zones of the oil-water transitions zone but values sharply increase to a mean of 14% in the lower sub-zone grading into the water-saturated portions of the reservoir and a very similar pattern is observed for permeability values. In the top of the water-filled zone, cavernous porosity with mean values of about 24% is found. Carbonate cements formed from the earliest marine to the late burial stage. Five calcite (Ca-1 through 5) and one dolomite (Dol) phase are recognized with phase Ca-4b recording the onset of hydrocarbon migration. Carbon and oxygen cross-plots clearly delineate different paragenetic phases with Ca-4 representing the most depleted δ¹³C ratios with mean values of about −21‰. During the main phase of oil emplacement, arguably triggered by far-field Alpine tectonics, carbonate cementation was slowed down and eventually ceased in the presence of hydrocarbons and corrosive fluids with temperatures of 110–140 °C and a micro-hiatal surface formed in the paragenetic sequence. These observations support the “oil-inhibits-diagenesis” model. The presence an earlier corrosion surface between phase Ca-3 and 4 is best assigned to initial pulses of ascending corrosive fluids in advance of hydrocarbons. The short-lived nature of the oil migration event found here is rather uncommon when compared to other carbonate reservoirs. The study is relevant as it clearly documents the strengths of a combined petrographic and geochemical study in order to document the timing of oil migration in carbonate reservoirs and its related cementation dynamics.     

Oil-bearing inclusions in vein quartz and calcite and,bitumens in veins: Testament to multiple phases of hydrocarbon migration in the Barrandian basin (lower Palaeozoic), Czech Republic

The petroleum charge history of the Barrandian basin was investigated by analysing quartz and calcite and organic phases that occur in veins and fractures cutting dolerite sills within the Liteň Formation (Silurian). The geochemical characteristics of fluid inclusions trapped in vein quartz and calcite, vein bitumens and adjacent potential source rocks when combined with burial and thermal history data reflect the presence of at least three separate hydrocarbon charge episodes. Solid highly reflecting (R_max = 0.92–1.49%) bitumen provides information on the first and oldest episode of oil migration. The precursor oil was probably derived relatively early during diagenesis from nearby organic-rich sediments and was subsequently thermally altered to form the solid bitumen.     

Basin geometry and salt diapirs in the Flinders Ranges,South Australia: Insights gained from geologically-constrained modelling of potential field data

The Adelaide Basin in Australia is a complex of late Neoproterozoic to Early Cambrian rift and sag basins which was inverted during the Cambro–Ordovician Delamerian Orogeny. The deposition of evaporitic sediments during the earliest stage of basin development in the late Neoproterozoic (Willouran age) played a major role in the subsequent tectonic evolution of the basin. Previous studies have shown that early mobilization, vertical transport and withdrawal of the evaporites influenced the sedimentation during the late Neoproterozoic and Early Cambrian. The evaporites also influenced deformation during the inversion of the basin and the development of the Delamerian fold and thrust belt. However, the control exerted by basement structures in the deposition of the evaporitic beds and the role of these tectonic structures in the later inversion of the basin have been poorly constrained.     

Salt tectonics and Pliocene stratigraphic framework at MC-118, Gulf of Mexico: An integrated approach with application to deep-water confined structures in salt basins

Integrated tectono-stratigraphic interpretation at MC-118 using 3D seismic, well logs and biostratigraphy reveals an area dominated by allochthonous salt and its related structures. OCS-Block MC-118 is located 130 km southeast of New Orleans on the Gulf of Mexico middle slope in ∼2600 ft of water.The area is divided into three domains based on their structural styles: (1) a western domain consisting of a basinward-dipping normal fault family and associated strata; (2) a central domain composed of a landward-plunging diapiric salt tongue canopy and associated salt welds, two flanking NE–SW trending salt-withdrawal mini-basins, and a crestal fault family; and (3) an eastern domain comprised of basinward/landward-dipping normal and listric normal fault families with their associated rollovers. These structural domains are genetically-and-kinematically related to the salt structure and extend beyond MC-118 boundaries. The salt structure is postulated to have evolved mostly passive, with punctuated active episodes, and by lateral spreading. This is part of a larger regional structure, eastern Gulf of Mexico, which involves some amalgamation between small-scale salt canopies and salt diapirs although collectively they appear mostly disconnected.A Pliocene (3.13–4.95 Ma) third-order genetic stratigraphic sequence, the focus of this study, is as much as ∼3600 ft thick within the mini-basins and contains: muddy mass transport complexes; sandy slope fans; muddy turbidites and condensed sections; and transitional facies flanking the salt structure that collectively have ponded and wedged external geometries. Mass transport complexes and muddy turbidites and condensed sections make most of the studied genetic sequence in a mud-dominated deltaic setting eastern Gulf of Mexico.Facies kinematic indicators and a matching number of genetic sequences accounted on the sea level chart support a eustatically driven mini-basin sedimentation. Nonetheless salt still plays a role in sedimentation (secondary/minor) by slumping generated during passive/active salt diapiric evolution.