Sedimentary controls on modern sand grain coat formation

Clay coated quartz grains can influence reservoir quality evolution during sandstone diagenesis. Porosity can be reduced and fluid flow restricted where grain coats encroach into pore space. Conversely pore-lining grain coats can restrict the growth of pore-filling quartz cement in deeply buried sandstones, and thus can result in unusually high porosity in deeply buried sandstones. Being able to predict the distribution of clay coated sand grains within petroleum reservoirs is thus important to help find good reservoir quality. Here we report a modern analogue study of 12 sediment cores from the Anllóns Estuary, Galicia, NW Spain, collected from a range of sub-environments, to help develop an understanding of the occurrence and distribution of clay coated grains. The cores were described for grain size, bioturbation and sedimentary structures, and then sub-sampled for electron and light microscopy, laser granulometry, and X-ray diffraction analysis. The Anllóns Estuary is sand-dominated with intertidal sand flats and saltmarsh environments at the margins; there is a shallowing/fining-upwards trend in the estuary-fill succession. Grain coats are present in nearly every sample analysed; they are between 1 μm and 100 μm thick and typically lack internal organisation. The extent of grain coat coverage can exceed 25% in some samples with coverage highest in the top 20 cm of cores. Samples from muddy intertidal flat and the muddy saltmarsh environments, close to the margins of the estuary, have the highest coat coverage (mean coat coverage of 20.2% and 21.3%, respectively). The lowest mean coat coverage occurs in the sandy saltmarsh (10.4%), beyond the upper tidal limit and sandy intertidal flat environments (8.4%), close to the main estuary channel. Mean coat coverage correlates with the concentration of clay fraction. The primary controls on the distribution of fine-grained sediment, and therefore grain coat distribution, are primary sediment transport and deposition processes that concentrate the clay fraction in the sediment towards the margins of the estuary. Bioturbation and clay illuviation/mechanical infiltration are secondary processes that may redistribute fine-grained sediment and produce grain coats. Here we have shown that detrital grain coats are more likely in marginal environments of ancient estuary-fills, which are typically found in the fining-upward part of progradational successions

Biofilm Origin of Clay-Coated Sand Grains

The presence of clay-sized particles and clay minerals in modern sands and ancient sandstones has long presented an interesting problem, because primary depositional processes tend to lead to physical separation of fine- and coarse-grained materials. Numerous processes have been invoked to explain the common presence of clay minerals in sandstones, including infiltration, the codeposition of flocculated muds, and bioturbation-induced sediment mixing. How and why clay minerals form as grain coats at the site of deposition remains uncertain, despite clay-coated sand grains being of paramount importance for subsequent diagenetic sandstone properties. We have identified a new biofilm mechanism that explains clay material attachment to sand grain surfaces that leads to the production of detrital clay coats. This study focuses on a modern estuary using a combination of field work, scanning electron microscopy, petrography, biomarker analysis, and Raman spectroscopy to provide evidence of the pivotal role that biofilms play in the formation of clay-coated sand grains. This study shows that within modern marginal marine systems, clay coats primarily result from adhesive biofilms. This bio-mineral interaction potentially revolutionizes the understanding of clay-coated sand grains and offers a first step to enhanced reservoir quality prediction in ancient and deeply buried sandstones

Thermochemical sulphate reduction can improve carbonate petroleum reservoir quality

Interest in the creation of secondary pore space in petroleum reservoirs has increased because of a need to understand deeper and more complex reservoirs. The creation of new secondary porosity that enhances overall reservoir quality in deeply buried carbonate reservoirs is controversial and some recent studies have concluded it is not an important phenomenon. Here we present petrography, geochemistry, fluid inclusion data, and fluid-rock interaction reaction modeling results from Triassic Feixianguan Formation, Sichuan Basin, China, core samples and explore the relative importance of secondary porosity due to thermochemical sulphate reduction (TSR) during deep burial diagenesis. We find that new secondary pores result from the dissolution of anhydrite and possibly from dissolution of the matrix dolomite. Assuming porosity before TSR was 16 % and the percentage of anhydrite was 6 %, modelling shows that, due to TSR, 1.6 % additional porosity was created that led to permeability increasing from 110 mD (range 72 to 168 mD within a 95% confidence interval) to 264 mD (range 162 to 432 mD within a 95 % confidence interval). Secondary porosity results from the density differences between reactant anhydrite and product calcite, the addition of new water during TSR, and the generation of acidity during the reaction of new H2S with the siderite component in pre-existing dolomite in the reservoir. Fluid pressure was high during TSR, and approached lithostatic pressure in some samples; this transient overpressure may have led to the maintenance of porosity due to the inhibition of compactional processes. An additional 1.6 % porosity is significant for reserve calculations, especially considering that it occurs in conjunction with elevated permeability that results in faster flow rates to the production wells

Multiphase dolomitization of deeply buried Cambrian petroleum reservoirs, Tarim Basin, north-west China

Cambrian dolostone reservoirs in the Tarim Basin, China, have significant potential for future discoveries of petroleum, although exploration and production planning is hampered by limited understanding of the occurrence and distribution of dolomite in such ancient rocks buried to nearly 8 km. The study herein accessed new drill core samples which provide an opportunity to understand the dolomitization process in deep basins and its impact on Cambrian carbonate reservoirs. This study documents the origin of the dolostone reservoirs using a combination of petrology, fluid‐inclusion microthermometry, and stable and radiogenic‐isotopes of outcrop and core samples. An initial microbial dolomitization event occurred in restricted lagoon environments and is characterized by depleted δ13C values. Dolomicrite from lagoonal and sabkha facies, some fabric‐retentive dolomite and fabric‐obliterative dolomite in the peloidal shoal and reef facies show the highest δ18O values. These dolomites represent relatively early reflux dolomitization. The local occurrence of K‐feldspar in dolomicrite indicates that some radiogenic strontium was contributed via terrigenous input. Most fabric‐retentive dolomite may have precipitated from seawater at slightly elevated temperatures, suggested by petrological and isotopic data. Most fabric‐obliterative dolomite, and medium to coarse dolomite cement, formed between 90°C and 130°C from marine evaporitic brine. Saddle dolomite formed by hydrothermal dolomitization at temperatures up to 170°C, and involved the mixing of connate brines with Sr‐ enriched hydrothermal fluids. Intercrystalline, moldic, and breccia porosities are due to the early stages of dolomitization. Macroscopic, intergranular, vuggy, fracture and dissolution porosity are due to burial‐related dissolution and regional hydrothermal events. This work has shown that old (for example, Cambrian or even Precambrian) sucrosic dolomite with associated anhydrite, buried to as much as 8000 m, can still have a high potential for hosting substantial hydrocarbon resources and should be globally targeted for future exploration

Clay coated sand grains in petroleum reservoirs: understanding their distribution via a modern analogue

Clay-coated grains can inhibit ubiquitous, porosity-occluding quartz cement in deeply buried sandstones and thus lead to anomalously high porosity. A moderate amount of clay that is distributed as grain coats is good for reservoir quality in deeply buried sandstones. Being able to predict the distribution of clay-coated sand grains in petroleum reservoirs is thus important to help find and exploit anomalously good reservoir quality. Here we have adopted a high-resolution, analogue approach, using the Ravenglass Estuary marginal-shallow marine system, in NW England, U.K. Extensive geomorphic mapping, grain-size analysis, and bioturbation-intensity counts were linked to a range of scanning electron microscopy techniques to characterize the distribution and origin of clay-coated sand grains in surface sediment. Our work shows that grain coats are common in this marginal–shallow marine system, but they are heterogeneously distributed as a function of grain size, clay fraction, and depositional facies. The distribution and characteristics of detrital-clay-coated grains can be predicted with knowledge of specific depositional environment, clay fraction percentage, and grain size. The most extensive detrital-clay-coated grains are found in sediment composed of fine-grained sand containing 3.5 to 13.0% clay fraction, associated with inner-estuary tidal-flat facies. Thus, against common convention, the work presented here suggests that, in deeply buried prospects, the best porosity might be found in fine-grained, clay-bearing inner-tidal-flat-facies sands and not in coarse, clean channel-fill and bar facies

Sulfur isotopic compositions of individual organosulfur compounds and their genetic links in the Lower Paleozoic petroleum pools of the Tarim Basin, NW China

During thermochemical sulfate reduction (TSR), H2S generated by reactions between hydrocarbons and aqueous sulfate back-reacts with remaining oil-phase compounds forming new organosulfur compounds (OSCs) that have similar δ34S values to the original sulfate. Using Compound Specific Sulfur Isotope Analysis (CSSIA) of alkylthiaadamantanes (TAs), alkyldibenzothiophenes (DBTs), alkylbenzothiophenes (BTs) and alkylthiolanes (TLs), we have here attempted to differentiate OSCs due to primary generation and those due to TSR in oils from the Tarim Basin, China. These oils were generated from Cambrian source rocks and accumulated in Cambrian and Ordovician reservoirs. Based on compound specific sulfur isotope and carbon isotope data, TAs concentrations and DBT/phenanthrene ratios, the oils fall into four groups, reflecting different extents of source rock signal, alteration by TSR, mixing events, and secondary generation of H2S. Thermally stable TAs, that were produced following TSR, rapidly dominate kerogen-derived TAs at low to moderate degrees of TSR. Less thermally stable TLs and BTs were created as soon as TSR commenced, rapidly adopted TSR-δ34S values, but they do not survive at high concentrations unless TSR is advanced and ongoing. The presence of TLs and BTs shows that TSR is still active. Secondary DBTs were produced in significant amounts, sufficient to dominate kerogen-derived DBTs, only when TSR was at an advanced extent. The difference in sulfur isotopes between (i) TLs and DBTs and (ii) BTs and DBTs and (iii) TAs and DBTs, represents the extent of TSR while the presence of TAs at greater than 20 μg/g represents the occurrence of TSR. The output of this study shows that compound specific sulfur isotopes of different organosulfur compounds, with different thermal stabilities and formation pathways, not only differentiate between oils of TSR and non-TSR origin, but can also reveal information about relative timing of secondary charge events and migration pathways

Particle size analysis: A comparison of laboratory-based techniques and their application to geoscience

In sedimentary geoscience, the particle size distribution (PSD) of a sediment has a fundamental effect on a sediment's ability to be entrained, eroded, and deposited. Therefore, it is crucial to accurately measure the PSD of sediments. Several laboratory-based methods of particle size analysis are commonly employed in geoscience; however, each method is based on different principles and the comparison of data from one technique to another is challenging. In this study, we have compared the output of four commonly-used laboratory-based techniques: Laser Particle Size Analysis (LPSA), optical point counting, 2D automated image analysis, and X-ray Computed Tomography (XCT). Each technique has been used to measure eight samples of spherical silica particles, all prepared with known particle size ranges. Spherical particles have been used to minimise the effects of variable sorting and particle shape on data output. Here we have compared the differences between the measured PSD and descriptors of each PSD, showing that, at small particle diameters (150 μm, LPSA overestimates the size of particles, due to limitations in the way that particle diameter is calculated by this technique. In contrast, 2D automated image analysis and optical point counting underestimate the diameters of particles, due to stereology (e.g., the effect of slicing particles during thin section preparation). Results from XCT analyses have the lowest values of sorting (range of measured particle diameters) and are therefore the most tightly constrained. In addition, XCT is the only 3D analysis method, allowing particle shape, orientation, and intraparticle porosity to be measured for a volume of material. We therefore conclude that XCT is the most accurate way to determine a grain size distribution in sediments

Improved imaging and analysis of chlorite in reservoirs and modern day analogues: new insights for reservoir quality and provenance

AbstractChlorite is a key mineral in the control of reservoir quality in many siliciclastic rocks. In deeply buried reservoirs, chlorite coats on sand grains prevent the growth of quartz cements and lead to anomalously good reservoir quality. By contrast, an excess of chlorite – for example, in clay-rich siltstone and sandstone – leads to blocked pore throats and very low permeability. Determining which compositional type is present, how it occurs spatially, and quantifying the many and varied habits of chlorite that are of commercial importance remains a challenge. With the advent of automated techniques based on scanning electron microscopy (SEM), it is possible to provide instant phase identification and mapping of entire thin sections of rock. The resulting quantitative mineralogy and rock fabric data can be compared with well logs and core analysis data. We present here a completely novel Quantitative Evaluation of Minerals by SCANning electron microscopy (QEMSCAN®) SEM–energy-dispersive spectrometry (EDS) methodology to differentiate, quantify and image 11 different compositional types of chlorite based on Fe : Mg ratios using thin sections of rocks and grain mounts of cuttings or loose sediment. No other analytical technique, or combination of techniques, is capable of easily quantifying and imaging different compositional types of chlorite. Here we present examples of chlorite from seven different geological settings analysed using QEMSCAN® SEM–EDS. By illustrating the reliability of identification under automated analysis, and the ability to capture realistic textures in a fully digital format, we can clearly visualize the various forms of chlorite. This new approach has led to the creation of a digital chlorite library, in which we have co-registered optical and SEM-based images, and validated the mineral identification with complimentary techniques such as X-ray diffraction. This new methodology will be of interest and use to all those concerned with the identification and formation of chlorite in sandstones and the effects that diagenetic chlorite growth may have had on reservoir quality. The same approach may be adopted for other minerals (e.g. carbonates) with major element compositional variability that may influence the porosity and permeability of sandstone reservoirs.</jats:p