Conventional Core Samples Research Articles

Research on loss rules of oil and gas in preserved shale cores after open air exposure

There is a large amount of oil and gas loss in traditional conventional core samples. Revealing the rules of oil and gas loss is of great significance for restore the pristine oil content and oil component in the shale. In this study, four preserved shale cores with different thermal maturity (Ro = 1.01–1.53%) and different total organic carbon content (TOC = 1.69–5.48 wt.%) were selected. The samples are obtained from the first member of the Qingshankou Formation in the Gulong Sag. Nuclear magnetic resonance (NMR) T1–T2 mapping and thermal desorption gas chromatography (TD–GC, at a constant temperature of 300°C for 3 min) were performed on the preserved cores and their replicas that were exposed in open air for different times, to study dynamic loss process and the molecular composition changes of shale oil. The results show that during exposure, shale experiences a large amount of oil loss, with a loss ratio of about 42%–78%, and the higher the maturity, the greater the loss ratio. The oil loss is mainly contributed by free oil, with a loss ratio as high as 88%. The adsorbed oil content, however, remains basically unchanged and has a good positive correlation with the TOC of shale. Once the cores were crushed, the gaseous hydrocarbon in oil was basically evaporated in just 5 min. After long-term storage, 90% of the C14- light hydrocarbon is lost, while the C14+ heavy hydrocarbon experiences basically no loss. Therefore, effective and timely analysis of preserved shales is extremely important. The oil content of uncrushed shale cores characterized by NMR T1–T2 mapping is much greater than that of the crushed sample measured by TD-GC, which means that NMR T1–T2 mapping can be important method to evaluate the original fluid saturation of shale.

Uji Laboratorium Sampel Core Plug untuk Menentukan Porositas, Permeabilitas dan Saturasi Minyak pada Reservoir Batugamping

Porosity, permeability, and fluid saturation (gas, oil, water) are three important physical properties of rocks, especially in oil and gas reservoirs (oil and gas) which are carried out in core rock analysis. The purpose of this study is to determine the relationship between porosity, permeability, and oil saturation in limestone (limestone) from a horizontal plug core sample to a vertical core plug sample, to be associated with its distribution vertically and horizontally (laterally). The research method used is a Lab Test conducted at the Routine Core Analysis (RCAL) Laboratory at PPTMBG "Lemigas" Jakarta, and graphical analysis of the measurement results. The core plug samples used were 21 (twenty one) which were taken horizontally and 10 were taken vertically, which has been described, from conventional core samples from limestone reservoirs. The results of his research are that the porosity values ​​of the vertical and horizontal samples of limestone have an indistinguishable trend, while limestones without chalky have a deeper trend, the porosity is greater, while porosity with chalky has a scatter trend, this indicates that the porosity of limestones is higher. influenced by lithological conditions or depending on the facies and the time of diagenesis, not depending on the depth (as in the case of sandstone). The value of oil saturation in the vertical and horizontal samples has a distribution that can be said to not show a certain trend or scatter. The relationship between porosity and permeability is exponentially proportional, regardless of depth and vertical or horizontal core sampling position. The value of porosity and permeability of limestone with the presence of chalky is more dominant, significantly increasing the value of porosity and permeability compared to that without the presence of chalky.

Determination of in situ hydrocarbon contents in shale oil plays. Part 1: Is routine Rock–Eval analysis reliable for quantifying the hydrocarbon contents of preserved shale cores?

An accurate determination of in situ hydrocarbon (oil) content is critical for the assessment of shale oil plays in terms of their total resources in place and recovery potential. Although correction of light hydrocarbon loss to the Rock–Eval S1 parameters on conventional core and cuttings samples has been recently attempted using preserved (e.g., sealed or pressure–preserved) cores, hydrocarbon evaporation loss during sample preparation and delay time before the actual commencement of Rock–Eval analysis has not received sufficient attention. In this study, a combination of petrophysical and geochemical techniques including Dean–Stark extraction, hydrogen nuclear magnetic resonance (1H-NMR) T1-T2 mapping, thermal desorption–gas chromatography (TD–GC) analysis, and Rock–Eval programmed pyrolysis were used in parallel on a set of 30 preserved shale cores to determine their total hydrocarbon contents. The preserved shale cores were analyzed in large pieces (e.g., 3–5 cm in size) by the former two petrophysical methods while using fine powder (e.g., <60 mesh) by the latter two thermal analytical methods. The total free hydrocarbon contents (equivalent of Rock–Eval S1) determined on the studied lacustrine shale samples with a Ro ranging from 1.00% to 1.51% followed the order of Dean–Stark (average 10.27 mg/g) ≈ NMR (10.34) ＞ TD–GC (6.65) ＞ Rock–Eval (3.93). The core crushing and grinding process required for both TD-GC and Rock–Eval pyrolysis analyses was found to cause a loss of approximately 35% to the in situ hydrocarbons. In addition, Rock–Eval analysis delay time (of 5 min) could lead to another 25% reduction to the total free hydrocarbons. In combination, sample preparation and analysis delay resulted in up to 60% reduction to the Rock–Eval S1 peaks for the preserved shale cores, and a 30% loss to the liquid (C6+) hydrocarbons in particular. To the best of our knowledge, this is the first reported observation that in situ light hydrocarbon contents can be severely underestimated by Rock–Eval and TD–GC analyses using powdered forms of preserved core samples. The extents of light hydrocarbon loss in conventional cores have been underestimated using the Rock–Eval S1 difference between preserved shale and its long–duration exposed replicates. Hence, when quantifying the hydrocarbon contents of the preserved shale samples, techniques utilizing larger rock pieces are highly recommended.

Implementation of lithofacies and microfacies types on reservoir quality and heterogeneity of the Late Cretaceous Upper Bahariya Member in the Shurouk Field, Shoushan Basin, North Western Desert, Egypt

The Late Cretaceous Upper Bahariya Member is one of the most prolific reservoir sequences in the North Western Desert of Egypt. In this paper, we describe core samples of the Upper Bahariya Member, including core photos, conventional core analysis, petrographical description, scanning electron microscope images, and XRD analysis. Samples for this study are from the reservoir sequence in four wells selected from the Shurouk Field in the Shoushan Basin to delineate the impact of the constraint mineral composition on the reservoir quality. The objective of this study is to get an accurate reservoir characterization of this reservoir by applying the rock typing technique to the studied sequence where four Lithofacies Associations (LFA1, LFA2, LFA3, and LFA4) and four corresponding Reservoir Rock Types (RRT1, RRT2, RRT3, and RRT4) were assigned. These are defined as 1) very fine massive sandstone (LFA1, RRT1), 2) laminated, cross-bedded and bioturbated sandstone (LFA2, RRT2), 3) laminated, highly argillaceous and ferruginated sandstone and siltstone (LFA3, RRT3), and 4) laminated and ferruginated siltstone and well cemented bioturbated limestone (LFA4, RRT4). Petrographically, these lithofacies were categorized into five microfacies; 1) glauconitic quartz arenite, 2) subfeldspathic arenite, 3) glauconitic sublithic arenite, 4) ferruginated subfeldspathic wackes, and 5) sandy fossiliferous packstone microfacies. Conventional core samples include bulk and grain densities (ρb and ρg, respectively), helium porosity (∅He), and horizontal and vertical permeabilities (kH and kV, respectively). The application of the Dykstra-Parsons technique to the available permeability data indicates that the studied sequence is extremely heterogeneous (heterogeneity factor (V) = 0.90). Based on the available samples, the normalized porosity index (∅z), reservoir quality index (RQI), flow zone indicator (FZI), and the discrete rock type values (DRT) were estimated to determine the reservoir quality. The RRT1 samples are characterized by the best reservoir properties (av. ∅He = 14.7%, av. kH 42.0 = md, av. RQI = 0.47 µm, av. FZI = 2.87 µm, and av. DRT = 13), whereas the lowest reservoir quality is assigned to the RRT4 samples (av. ∅He = 18.8%, av. kH 0.30 = md, av. FZI = 0.15 µm, av. RQI = 0.04 µm, and av. DRT = 7). The low reservoir quality of the RRT4 is primarily attributed to the predominance of lower quality features (compaction effect, cementation, and presence of glauconite and authigenic minerals). Following the Improved Stratigraphic Modified Lorenz (ISML plot), the Upper Bahariya reservoir is subdivided into five Hydraulic Flow Units (HFUs) such as the HFU-2, and the HFU-4 that are considered superconductive flow units that alternate with three poorly hydraulic conductive HFUs (HFU-1, HFU-3, and HFU-5). The present integrated sedimentological and petrophysical workflow is considered a significant study of the Shoushan basin which can improve exploration activities as well as production optimization. In addition, dividing the studied clastic sequence into five microfacies association and four reservoir rock types can be extended to other equivalent subsurface Late Cretaceous clastic sedimentary rocks in the vicinity and other basins.

3D-Printing Replication of Porous Media for Lab-Scale Characterization Research.

Simplifying fluid-flow physics in conventional reservoirs is convenient by assuming uniform lithology and system-geometry with minimal rock/hydrocarbon interactions. Such simplification restrains mathematical models’ ability to simulate unconventional reservoirs’ actual flow behavior and production performance. Researchers can achieve precise adaption for the physics of fluid flow in porous media if they geometrically characterize the system under study appropriately, and there are minimal interactions indeed. 3D-printed replicas of porous-rock samples obey this criterion. In this work, we used image-processing tools used for creating presentable porous and permeable replicas of different scales and configurations of the petroleum system from lab-scale to field-scale. The workflow of 3D-printed replicas creation is presented for replicas of conventional core samples, naturally and synthetically fractured cores, geological drilling units of multistage fractured horizontal wells, and full-field models, e.g., Norne field in Norway. These samples are ideal for experimentally testing the validity of the analytical or numerical models of oil and gas reservoirs in the laboratory, along with judging the quality of reservoirs’ characterization. These replicas’ ideality of these results from limited uncertainties of the geometry of the system under study and fluid/rock interactions because of the uniform composition. For validation purposes, 3D-printed replicas with different materials and 3D-printing technologies were created based on a reconstructed image-processed CT scan of their original Berea sandstone. These replicas were tested for storage capacity (porosity) and transport capacity (permeability) and compared with their original sample’s capacities. The matched results proved replicas’ ability to be used in oil and gas laboratory experimental research.

How pore structure non‐stationarity compromises flow properties representativity (REV) for soil samples: Pore‐scale modelling and stationarity analysis

AbstractClassic soil physics relies heavily on the concept of representative elementary volume (REV), which is necessary to perform upscaling from the studied soil samples and parameterize continuum scale hydrological models (e.g., based on Richards or Darcy equations). In this paper, we explore the boundaries of the classic REV concept and conventional representativity studies that claim REV for any given physical property, and that its values converge to a steady value with increasing sample volume. We chose two undisturbed soil samples of standard size from Ah and B horizons, subcropped two subvolumes within each of them and performed pore‐scale flow simulations using binarized X‐ray microtomography scans as input data. The volume of the simulation domains was 9003 voxels, with a physical volume within two orders of magnitude of the whole soil core. Based on the 3D pore geometry images and the resulting flow velocity and pressure fields, we performed REV analysis for the saturated hydraulic conductivity and porosity. Although in general subvolumes showed classical REV behaviour (convergence of porosity and saturated hydraulic conductance (Ksat)to plateau‐like behaviour), their flow properties converged to different REV values. We also evaluated the stationarity of pore structures by computing the directional correlation functions to explain the observed non‐unique behaviour. We concluded that neither of the studied samples can be considered to be representative due to their structural non‐stationarity. We extensively discussed the implications of these results for the upscaling and parameterization of continuum‐scale flow models. We argued that the plateau in Ksat (or any other physical property) is a necessary, but insufficient, condition for the REV, which requires (at least) pore structure stationarity as an additional criterion. REV as a concept is much broader than previously anticipated and the possibility of establishing REVs in structured soils will require an analysis of tensorial flow properties with correct boundary conditions, multiscale soil structure imaging with stationarity analysis, and pore‐scale simulations on fused multiscale images.Highlights Ksat analysis within subvolumes showed classical REV behaviour but resulted in non‐unique REVs for the soil samples studied Based on the stationarity analysis we argued that the conventional soil core samples studied were not REVs Plateau‐like behaviour in physical properties is a necessary but insufficient condition for REV Soil structure information is necessary to properly establish REV or upscale flow properties

Sedimentological analysis and reservoir quality of the early Cenomanian transgressive sandstones, northern Western desert, Egypt

Depicting depositional models of transgressive sandstone reservoirs is challenging due to their internal complexity and limited case studies. This study presents an example for transgressive sandstone reservoirs from the Bahariya Formation at Hayat-Yasser oil field, Shushan Basin (northern Western Desert, Egypt). The upper part of the Bahariya Formation accumulated in an estuarine setting as a consequence of a successive sea level rise. Detailed reservoir characterization, employing sequence stratigraphic and sedimentological approaches, revealed that the studied reservoir consists of a mixed siliciclastic-carbonate transgressive estuarine-shelf succession. Four conventional core samples of this succession at Khalda ridge (Shushan Basin), permit the analysis of their sedimentology and internal architecture (mesoscopic heterogeneities) along correlation lines parallel or slightly oblique to depositional dip. The succession consists of six backstepping parasequence sets that record the overall shift from tidal-dominated to wave-dominated estuaries/bays. The transgressive component of the parasequences sets includes bay mudstones, flood-tidal deltas, and shoreface/barrier deposits; while the regressive component includes estuarine point bars, bay head deltas, and tidal deltas. The reservoir properties show significant variation according to the facies assemblages. The tidally-dominated estuarine channels show low net-to-gross, as it is characterized by lenticular sandstone bodies with several lateral and vertical baffles and barriers. On the other hand, the shoreface/barrier and tidal delta sandstones show high net-to-gross and consist of amalgamated sandstone bodies with little mud barriers or baffles. Petrographically, the upper Bahariya reservoir includes intergranular and secondary porosities. The microscopic heterogeneities are mainly due to the fine grain nature, poor sorting, presence of matrix, and continuous mud barriers or baffles. Destruction of porosity, affecting the reservoir quality, occurred by silica overgrowths, ferroan calcite, grain coating chlorite, and kaolinite cementation, as well as compaction. Feldspar dissolution is the main diagenetic process responsible for the formation of secondary porosity, enhancing the reservoir quality.

Acidizing of conventional and tight sandstone formation using chelating agents: mineralogical prospect

Stimulation of the sandstone reservoir requires a mixture of acids such as mud acid, which assist in enlarging the microscopic paths by dissolving the siliceous fines or clays near the well-bore region. As a result, the formation permeability and porosity can be enhanced. In deeper wells, the temperature exceeds 200 °F, at these temperature ranges, problems can arise. For example, the use of mud acid mixtures can lead to issues like precipitations, corrosion, early consumption of acids, leading to lesser acid efficiency. In this study, the core flooding apparatus was used for acidizing experiments, designed to dissolve minerals and to analyze the changes in petrophysical parameters such as porosity, permeability, and mineralogy. Conventional and tight sandstone core samples were acidized using different chelating acids such as Hydroxyethylethylenediaminetriacetic acid (HEDTA), Ethylenediaminetetraacetic acid (EDTA) and Glutamic acid (GLDA) at high-temperature conditions. Analytical studies (mineral mass, pore size distribution, topology, grain size distribution, and density distribution were conducted using Tescan Integrated Mineral Analysis (TIMA). The obtained results showed that chelating agent HEDTA created more pore spaces in the core samples and is effective in dissolving positive ions. Also, the permeability was observed to be doubled by its application which could be effective in alteration of pore topology of the sandstone cores.

Constraints on the fluid supply rate into and through gas hydrate reservoir systems as inferred from pore-water chloride and in situ temperature profiles, Krishna-Godavari Basin, India

Abstract We estimate the rate of upward pore fluid flow and chlorinity (Cl−) concentrations at depth through a joint analysis of Cl− concentration and temperature versus depth profiles obtained from gas hydrate related test sites drilled and cored in the Krishna-Godavari Basin off the eastern coast of India. Cl−, measured on conventional core samples, decreases with depth at all sites but some of the Cl−profiles show a prominent convex shape, whereas in situ temperature profiles, obtained by the Advanced Piston Coring Temperature probe, are mostly linear at all sites established during the National Gas Hydrate Program 02 Expedition (NGHP-02). Assuming a one-dimensional, time-dependent model for the advection of pore fluid including the sedimentation effect and depth-dependent diffusivity, we estimate darcy velocity and the Cl− concentrations at depth. The best-fit darcy velocity of 1.2–1.6 × 10−11 m/s was estimated for the sites along the crest of the regional anticlinal structure in the NGHP-02 Area B, which was significantly faster than those on the flanks of the anticline. Because the thermal diffusion coefficient is much larger than the chloride ion diffusion coefficient, estimated darcy velocities are not great enough to generate nonlinear temperature profiles with depth, which is consistent with observed linear thermal profiles.

Micellar-polymer for enhanced oil recovery for Upper Assam Basin

Abstract One of the major enhanced oil recovery (EOR) processes is chemical flooding especially for the depleted reservoirs. Chemical flooding involves injection of various chemicals like surfactant, alkali, polymer etc. to the aqueous media. Bhogpara and Nahorkatiya are two depleted reservoirs of upper Assam basin where chemical flooding can be done to recover the trapped oil that cannot be recovered by conventional flooding process. Micellar-polymer (MP) flooding involves injection of micelle and polymer to the aqueous phase to reduce interfacial tension and polymer is added to control the mobility of the solution, which helps in increasing both displacement and volumetric sweep efficiency and thereby leads to enhanced oil recovery. This work represents the use of black liquor as micelle or surfactant that is a waste product of Nowgong Paper Mills, Jagiroad, Assam, which is more efficient than the synthetic surfactants. The present study examines the effect of MP flooding through the porous media of two depleted oil fields of upper Assam basin i.e. Bhogpara and Nahorkatiya for MP EOR. This work also compares the present MP flood with the earlier work done on surfactant (S) flooding. It was experimentally determined that the MP flood is more efficient EOR process for Bhogpara and Nahorkatiya reservoirs. The study will pertain to the comprehensive interfacial tension (IFT) study and the displacement mechanism in conventional core samples.

Experimental Study on Water Sensitivity Difference Based on Oiliness of Porous Medium Rock

This study presents the differences of water sensitivity experiment of porous medium rock between conventional dry core samples and oil-bearing core. The comparison was made to analyze the impact of single-phase fluid and multiphase fluid on the actual sensitivity of rock. The nuclear magnetic resonance (NMR) test was carried out to reveal the distribution of oil in porous medium and the microscopic influence mechanism of oil phase. The study shows that the initial oil in place could isolate the clay from water, and then the expansion and the migration of the clay were prevented to reduce the decrease of degree of damage.

CHEMICAL COMPOSITION OF THE MINERAL MATTER OF THE ATTARAT UM GHUDRAN OIL SHALE, CENTRAL JORDAN

The concession area of the Jordan Oil Shale Energy Co (JOSE) is located in the southern border zone of the Attarat Um Ghudran deposit, next to the Wadi Maghara deposit, both consisting of marinite type oil shale (OS). These deposits of the Upper Cretaceous to Lower Paleogene Muwaqqar Chalk-Marl Formation form a huge north-southward elongated oil shale basin in Central Jordan, with resources over 55 billion tons. JOSE has drilled a regular grid of boreholes with a full coring of the up to 90 m thick OS seam and its lower and upper contact layers. Visually, the OS unit is a rather homogenous dark-colored (grey, black, brownish grey) succession of finely bedded (laminated) kerogen-bearing carbonate rocks that has been in earlier papers described as a uniform lithological unit. The aim of the geological and lithological studies of the JOSE exploration area was (i) to investigate the vertical variation of OS composition and, if present, to define layers within the OS unit, and (ii) to identify lithological varieties and chemical composition of OS present in different layers. On the basis of field evidence, downhole gamma-logging, chemical analyses and other criteria, an original detailed scheme of the layered structure of oil shale and barren rocks was introduced. A total of eight OS layers (indexed as A, B1, B2, C, D, E1, E2, E3) and at least four barren dolomitic limestone interlayers were distinguished. The present publication is dedicated to the chemical study of the layers and the total OS seam. A representative gapless collection of 632 conventional core samples from 12 cores serves as the base for the comparative study of the layers. Two main (SiO2, CaO) and two subordinate chemical (Al2O3 and P2O5) components of the mineral matter (MM), and loss on ignition (LOI 500 °C) approximately reflecting the content of organic matter (OM), are the basic variables dis- cussed. Contents of SiO2 and CaO always show negative correlation,

Reservoir characterization of Scollard-age fluvial sandstones, Alberta foredeep

A detailed laboratory study of 53 sandstone samples from 23 outcrops and 156 conventional core samples from the Maastrichtian-Paleocene Scollard-age fluvial strata in the Western Canada foredeep was undertaken to investigate the reservoir characteristics and to determine the effect of diagenesis on reservoir quality. The sandstones are predominantly litharenites and sublitharenites, which accumulated in a variety of fluvial environments. The porosity of the sandstones is both syn-depositional and diagenetic in origin. Laboratory analyses indicate that porosity in sandstones from outcrop samples with less than 5% calcite cement averages 14%, with a mean permeability of 16 mD. In contrast, sandstones with greater than 5% calcite cement average 7.9% porosity, with a mean permeability of 6.17 mD. The core porosity averages 17% with 41 mD permeability. Cementation coupled with compaction had an important effect in the destruction of porosity after sedimentation and burial. The reservoir quality of sandstones is also severely reduced where the pore-lining clays are abundant (>15%). The potential of a sandstone to serve as a reservoir for producible hydrocarbons is strongly related to the sandstone’s diagenetic history. Three diagenetic stages are identified: eodiagenesis before effective burial, mesodiagenesis during burial, and telodiagenesis during exposure after burial. Eodiagenesis resulted in mechanical compaction, calcite cementation, kaolinite and smectite formation, and dissolution of chemically unstable grains. Mesodiagenesis resulted in chemical compaction, precipitation of calcite cement, quartz overgrowths, and the formation of authigenic clays such as chlorite, dickite, and illite. Finally, telodiagenesis seems to have had less effect on reservoir properties, even though it resulted in the precipitation of some kaolinite and the partial dissolution of feldspar.

Leaves in turbidite sands: The main source of oil and gas in the deep-water Kutei Basin, Indonesia: Discussion

Saller et al. (2006) have concluded that leaves in the upper Miocene turbidite sands were the main source of oil and gas in the deep-water Kutei Basin, East Kalimantan (Borneo), Indonesia. They have reported that oils from the Kutei Basin have high (4–7) pristane/phytane ratios, suggesting a coaly organic source. This is consistent with other observations made on oils from the Gippsland Basin in Australia, showing high pristane/phytane ratios (5–6) that were attributed to coniferous rain forests and related land-plant organic matter (Shanmugam, 1985). Saller et al. (2006) have also concluded that leaf fragments were carried into deep water along with sand by turbidity currents during lowstands of sea level. This conclusion deserves close scientific scrutiny. Although Saller et al. (2006) have discussed both geochemical and sedimentological aspects, I confine this discussion to sedimentological details. I also take this opportunity to introduce more clarity into our understanding of deep-water deposition through discussing conceptual, observational, and interpretational problems. First, Saller et al. (2006, p. 1588) stated that “Specific well names and depths are not included in this manuscript for confidentiality reasons.” The strength of any scientific article is its transparency of data, which provides other researchers an opportunity to verify the conclusions of an article without constraints. Saller et al. used cuttings samples from 50 wells and conventional core samples from 16 wells, but because they did not provide a map showing well locations, it is impossible to evaluate the relative position of a sample with respect to the paleoshelf edge. This is critical to the central theme of this article, which is the source of land-plant organic matter (i.e., highstand delta versus lowstand shelf-edge delta). Saller et al. could have included a location map of wells, but could have changed the original well names. Second, the basic tenet of …

Lithofacies summary of the Mississippian Barnett Shale, Mitchell 2 T.P. Sims well, Wise County, Texas

The Mississippian Barnett Shale is an important hydrocarbon source rock and has recently developed into a very active gas-shale play. Commonly viewed as a homogeneous black shale, the Barnett actually consists of a variety of organic-rich lithofacies of siliceous, calcareous, or phosphatic composition. Recognition of the different lithofacies is an important step in the evaluation of gas in place, flow capacity, and mechanical properties of the Barnett. Petrographic study of conventional core samples from the lower part of the Barnett has led to the recognition of the following rock types: organic-rich black shale, fossiliferous shale, dolomite rhomb shale, dolomitic shale, phosphatic shale, and concretionary carbonate. Measured total organic carbon values, averaged by rock type, range by a factor of nearly two, with the organic-rich shale and phosphatic shale having the highest values. The development of these lithofacies is a result of suspension fallout and sediment gravity flows combined with the extensive early microbial alteration of abundant organic matter. The lithofacies vary in petrophysical and mechanical properties, as well as organic content.

Diagenesis and porosity reduction in the Late Cretaceous Wyandot Formation, Offshore Nova Scotia: a comparison with Norwegian North Sea chalks

Abstract Porous chalk units have produced significant oil and gas discoveries around the world, including the world-class Tor Field of the Norwegian North Sea. On the Scotian Shelf of eastern Canada, the Upper Cretaceous Wyandot Formation is widespread, extending approximately 500 km along the length of the margin, and consists primarily of limestone with major chalk intervals. These chalks have porosities of up to 30% and are the reservoir for a gas and oil discovery at the Primrose N-50 well (1972) and a gas show at the Eagle D-21 well (1972). However, despite its potential as a hydrocarbon reservoir and/or seal, the Wyandot Formation is under-studied. In this paper, the Wyandot chalk is studied using conventional core samples, petrophysical logs, isotope geochemistry and SEM images to enhance the understanding of the depositional history, diagenesis and porosity-reducing mechanisms within the Wyandot Formation. Results indicate that the Wyandot chalks are in situ pelagic deposits, as opposed to the allochthonous North Sea chalks, and that mechanical compaction and dissolution/re-precipitation are the dominant mechanisms of porosity reduction. Given that significant volumes of Wyandot chalk have been eroded on parts of the Scotian Shelf, it is possible that North Sea type allochthonous reservoirs exist is distal locations on the Scotian Slope, and therefore an increased understanding of the sedimentology and porosity distribution of the in situ Wyandot Formation is important for further exploration in this frontier area.

Demonstration of a method for the direct determination of polycyclic aromatic hydrocarbons in submerged sediments.

We describe the development of a novel method for real-time in situ characterization of polycyclic aromatic hydrocarbons (PAHs) in submerged freshwater sediments. Laser-induced fluorescence (LIF) spectroscopy, a mature technique for PAH characterization in terrestrial sediments, was adapted for shipboard use. A cone penetrometer-type apparatus was designed for probe penetration at a constant rate (1 cm/s) to a depth of 3 m. A field-portable LIF system was used for in situ measurements in which the output of a pulsed excimer laser was transmitted by optical fiber to a sapphire window (6.4-mm o.d.) in the probe wall; fluorescent emission was collected by a separate optical fiber for transmission to the spectrometer on deck. Four wavelengths (340, 390, 440, 490 nm) were selected via optical delay lines, and multiple-wavelength waveforms were created. These multiple-wavelength waveforms contain information on the fluorescence frequency, intensity, and emission decay rate. Field testing was conducted at 10 sites in Milwaukee Harbor (total PAH concentrations ranged from approximately 10 to 650 microg/g); conventional sediment core samples were collected concurrently. The core samples were analyzed by EPA methods 3545 (pressurized fluid extraction, PFE) and 8270C (gas chromatography-mass spectrometry, GC-MS) for PAHs. A partial least-squares regression (PLSR) model wasthen created based on laboratory LIF measurements and PFE-GC-MS of the core samples. The PLSR model was applied to the in situ field test data, and 13 of the 16 EPA-regulated PAHs were quantified with a relative error of <30% overall (the remaining three PAHs were found at levels insufficient to quantify). We additionally describe preliminary source apportionment relationships that were revealed by the PLSR model for the in situ LIF measurements.

A proposed latest Triassic to earliest Cretaceous microfossil biozonation for the English Channel and its adjacent areas

Abstract Three detailed biostratigraphic zonations, based on ostracods, foraminiferids and dinocysts, are proposed for the latest Triassic through to the earliest Cretaceous of the Portland-Wight Basin and its adjacent areas. A total of 112 zones-zonules (34 ostracod zones/subzones, 25 foraminiferid zones, 53 dinoflagellate zones, subzones and zonules) are recognized. All three zonation schemes are based on samples obtained from both outcrop (the Dorset coast) and boreholes, the latter from ditch cuttings, with some conventional and sidewall core samples, in association with published data, and have where possible been calibrated to the standard ammonite zones recognized throughout northwest Europe.

Distribution of pollen and spores in a subsurface marine Wilcox (Paleocene‐Eocene) section in southwest Louisiana

Abstract Fifty conventional core samples from the Ragley Lumber #D1 well located in Allen Parish, Louisiana (Sec 29, T5S, R7W) were analysed for terrigenous palynomorphs. The sediment was deposited during the Sabinian in a marine environment as evidenced by the presence of in situ dinocysts and acritarchs in every sample. One hundred twenty‐nine terrigenous taxa are recognized as compared with marine palynomorph diversity of 46 taxa. Single sample diversity among the terrigenous palynomorph component ranged from 23 to 65 taxa, while single sample marine palynomorph diversity ranged from 7 to 25 taxa. High terrigenous diversity intervals possibly indicate sourcing from multiple onshore environments or a single onshore environment with a very diverse flora. Because the terrigenous component is reworked from the onshore environments to the offshore ones, intervals of terrigenous abundance possibly indicate deltaic progradation associated with changes in sediment supply or sea‐level. Confirmation of this inte...

Distribution of dinoflagellates in a subsurface marine Wilcox (Paleocene‐eocene) section in southwest louisiana

Abstract Fifty conventional core samples from the Ragley Lumber # 1 well located in Allen Parish Louisiana (Sec 29, T5S, R7W) were analyzed for palynomorphs. Dinoflagellate cysts, not considered to be recycled, were present in all samples along with abundant to very abundant pollen, spores and fungal spores. Dinoflagellate cyst abundances varied considerably from sparse ( 100 cysts per sample). Preservation also displayed considerable range, even within the same sample. Biostratigraphically useful taxa include: Adnatosphaeridium multispinosum, Apectodinium homomorphum, Areosphaeridium dictyoplokus, Deflandrea phosphoritica, Spinidinium sagittula, Lingulodinium machaerophorum, Muratodinium fimbratum, Palaeocystodinium golzowense, and Hafniasphaera septata. Other taxa described include: Achomosphaera alcicornu, Cleistosphaeridium diversispinosum, Cordosphaeridium inodes, Diphyes colligerum, Operculodinium centrocarpum, Polysphaeridium subtile, Trichodinium hirsuitum, and...