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1.
In the Kopet-Dagh Basin of Iran, deep-sea sandstones and shales of the Middle Jurassic Kashafrud Formation are disconformably overlain by hydrocarbon-bearing carbonates of Upper Jurassic and Cretaceous age. To explore the reservoir potential of the sandstones, we studied their burial history using more than 500 thin sections, supplemented by heavy mineral analysis, microprobe analysis, porosity and permeability determination, and vitrinite reflectance.The sandstones are arkosic and lithic arenites, rich in sedimentary and volcanic rock fragments. Quartz overgrowths and pore-filling carbonate cements (calcite, dolomite, siderite and ankerite) occluded most of the porosity during early to deep burial, assisted by early compaction that improved packing and fractured quartz grains. Iron oxides are prominent as alteration products of framework grains, probably reflecting source-area weathering prior to deposition, and locally as pore fills. Minor cements include pore-filling clays, pyrite, authigenic albite and K-feldspar, and barite. Existing porosity is secondary, resulting largely from dissolution of feldspars, micas, and rock fragments, with some fracture porosity. Porosity and permeability of six samples averages 3.2% and 0.0023 mD, respectively, and 150 thin-section point counts averaged 2.7% porosity. Reflectance of vitrinite in eight sandstone samples yielded values of 0.64-0.83%, in the early mature to mature stage of hydrocarbon generation, within the oil window.Kashafrud Formation petrographic trends were compared with trends from first-cycle basins elsewhere in the world. Inferred burial conditions accord with the maturation data, suggesting only a moderate thermal regime during burial. Some fractures, iron oxide cements, and dissolution may reflect Cenozoic tectonism and uplift that created the Kopet-Dagh Mountains. The low porosity and permeability levels of Kashafrud Formation sandstones suggest only a modest reservoir potential. For such tight sandstones, fractures may enhance the reservoir potential.  相似文献   

2.
The compositions, distribution and its interaction with rocks of the evolving pore fluids controls the distribution of carbonate cements and reservoir storage spaces. The reservoir quality of the red-bed sandstone reservoirs in the Dongying Depression was investigated by an integrated and systematic analysis including carbonate cement petrology, mineralogy, carbon and oxygen isotope ratios and fluid inclusions. The investigation was also facilitated by probing the mineral origins, precipitation mechanisms, pore fluid evolution and distribution, and water-rock interaction of carbonate cements and their influences on reservoir quality. Diagenetic-evolving fluids in the interbedded mudstones are the main source for the precipitation of calcite cements that completely fill the intergranular volume (CFIV calcite) with heavier oxygen and carbon isotopes. The ferro-carbonate cements in the reservoir sandstone are enriched in lighter carbon and oxygen isotopes. In addition to the cations released by the conversion of clay minerals in reservoirs, products of organic acid decarboxylation and the associated feldspar dissolution process provide important sources for such carbonate cementation. The carbon isotopes of CO2 and the oxygen isotopic composition of fluids equilibrated with the CFIV calcite, ferro-calcite, dolomite and ankerite cements indicate that the pore in the red-bed reservoirs experienced high salinity fluids, which evolved from the early-formed interbedded mudstones, through organic acid input and to organic acid decarboxylation. Pore fluids from nearby mudstones migrated from the edge to the centre of sandbodies, causing strong calcite cementation along the sandbody boundaries and forming tight cementation zones. Pore fluids associated with organic CO2 and acids and organic acid decarboxylation are mainly distributed in the internal portion of sandbodies, causing feldspar dissolution and precipitation of ferro-carbonate cements. The distribution of pore fluids caused the zonal distribution of carbonate cements in sandbodies during different periods. This may be advantageous to preserve the porosity of reservoirs as exemplified by the distribution of high-quality reservoirs in the red-bed sandbodies.  相似文献   

3.
The Yuanba gas field in the Permian Changxing Formation (P2c), which exhibits wide variations in its hydrogen sulfide (H2S) concentration (1.20–12.16%), is a typical sour gas field in the northern Sichuan Basin. The sulfur-rich reservoir's solid bitumen (atomic S/C ratios are 0.032–0.142), and late calcite cement δ13C values, which are smaller than the δ13C values of the host dolostone, indicate that the H2S originated from thermal sulfate reduction (TSR) and oil was involved in TSR. The gas souring index (GSI) of P2c's gases is generally lower than 0.1. The ethane δ13C values increase as the GSI increases, although no obvious increase was observed in the methane δ13C values. The calcite cements' δ13C values (−15.36 to +4.56‰) in dolostone are heavier than the typical reported values, which implies that only limited heavy hydrocarbon gases were involved in TSR. No anhydrites developed in P2c's reservoirs, and dissolved sulfate anions (SO42−) were mainly enriched during dolomitization. Insufficient dissolved SO42− most likely caused the lower H2S concentrations in the Permian to Triassic reservoirs in the northeastern Sichuan Basin compared to the Permian Khuff Formation in Saudi Arabia and the Jurassic Smackover Formation in Mississippi. Except for the SO42− in residual water in paleo-oil zones, SO42− from bottom water may also be involved in TSR; therefore, oil reservoirs with bottom water have more SO42− and can produce more H2S than pure oil reservoirs. This phenomenon may be the main cause of the great difference in the H2S concentrations between reservoirs, while gravitational differentiation during late uplift most likely creates differences in H2S concentrations in a single reservoir. Carbon dioxide (CO2), which has a relatively heavy δ13C value (−3.9 to −0.3‰), may be the combined result of TSR, the balance between CO2 and inorganic fluid systems, and carbonate decomposition.  相似文献   

4.
This paper investigates the reservoir potential of deeply-buried Eocene sublacustrine fan sandstones in the Bohai Bay Basin, China by evaluating the link between depositional lithofacies that controlled primary sediment compositions, and diagenetic processes that involved dissolution, precipitation and transformation of minerals. This petrographic, mineralogical, and geochemical study recognizes a complex diagenetic history which reflects both the depositional and burial history of the sandstones. Eogenetic alterations of the sandstones include: 1) mechanical compaction; and 2) partial to extensive non-ferroan carbonate and gypsum cementation. Typical mesogenetic alterations include: (1) dissolution of feldspar, non-ferroan carbonate cements, gypsum and anhydrite; (2) precipitation of quartz, kaolinite and ferroan carbonate cements; (3) transformation of smectite and kaolinite to illite and conversion of gypsum to anhydrite. This study demonstrates that: 1) depositional lithofacies critically influenced diagenesis, which resulted in good reservoir quality of the better-sorted, middle-fan, but poor reservoir quality in the inner- and outer-fan lithofacies; 2) formation of secondary porosity was spatially associated with other mineral reactions that caused precipitation of cements within sandstone reservoirs and did not greatly enhance reservoir quality; and 3) oil emplacement during early mesodiagenesis (temperatures > 70 °C) protected reservoirs from cementation and compaction.  相似文献   

5.
A great difference exists between the hydrocarbon charging characteristics of different Tertiary lacustrine turbidites in the Jiyang Super-depression of the Bohai Bay Basin, east China. Based on wireline log data, core observation and thin-section analyses, this study presents detailed reservoir property data and their controlling effects from several case studies and discusses the geological factors that govern the hydrocarbon accumulation in turbidite reservoirs. The lacustrine fluxoturbidite bodies investigated are typically distributed in an area of 0.5–10 km2, with a thickness of 5–20 m. The sandstones of the Tertiary turbidites in the Jiyang Super-depression have been strongly altered diagenetically by mechanical compaction, cementation and mineral dissolution. The effect of compaction caused the porosity to decrease drastically with the burial depths, especially during the early diagenesis when the porosity was reduced by over 15%. The effect of cementation and mineral dissolution during the late-stage diagenesis is dominated by carbonate cementation in sandstones. High carbonate cement content is usually associated with low porosity and permeability. Carbonate dissolution (secondary porosity zone) and primary calcite dissolution is believed to be related to thermal maturation of organic matter and clay mineral reactions in the surrounding shales and mudstone. Two stages of carbonate cementation were identified: the precipitation from pore-water during sedimentation and secondary precipitation in sandstones from the organic acid-dissolved carbonate minerals from source rocks. Petrophysical properties have controlled hydrocarbon accumulation in turbidite sandstones: high porosity and permeability sandstones have high oil saturation and are excellent producing reservoirs. It is also noticed that interstitial matter content affects the oil-bearing property to some degree. There are three essential elements for high oil-bearing turbidite reservoirs: excellent pore types, low carbonate cement (<5%) and good petrophysical properties with average porosity >15% and average permeability >10 mD.  相似文献   

6.
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.  相似文献   

7.
The Jiaolai Basin (Fig. 1) is an under-explored rift basin that has produced minor oil from Lower Cretaceous lacustrine deltaic sandstones. The reservoir quality is highly heterogeneous and is an important exploratory unknown in the basin. This study investigates how reservoir porosity and permeability vary with diagenetic minerals and burial history, particularly the effects of fracturing on the diagenesis and reservoir deliverability. The Laiyang sandstones are tight reservoirs with low porosity and permeability (Φ < 10% and K < 1 mD). Spatial variations in detrital supply and burial history significantly affected the diagenetic alterations during burial. In the western Laiyang Sag, the rocks are primarily feldspathic litharenites that underwent progressive burial, and thus, the primary porosity was partially to completely eliminated as a result of significant mechanical compaction of ductile grains. In contrast, in the eastern Laiyang Sag, the rocks are lithic arkoses that were uplifted to the surface and extensively eroded, which resulted in less porosity reduction by compaction. The tectonic uplift could promote leaching by meteoric water and the dissolution of remaining feldspars and calcite cement. Relatively high-quality reservoirs are preferentially developed in distributary channel and mouth-bar sandstones with chlorite rims on detrital quartz grains, which are also the locations of aqueous fluid flow that produced secondary porosity. The fold-related fractures are primarily developed in the silt–sandstones of Longwangzhuang and Shuinan members in the eastern Laiyang Sag. Quartz is the most prevalent fracture filling mineral in the Laiyang sandstones, and most of the small-aperture fractures are completely sealed, whereas the large-aperture fractures in a given set may be only partially sealed. The greatest fracture density is in the silt–sandstones containing more brittle minerals such as calcite and quartz cement. The wide apertures are crucial to preservation of the fracture porosity, and the great variation in the distribution of fracture-filling cements presents an opportunity for targeting fractures that contribute to fluid flow.  相似文献   

8.
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 Q86.0F3.1R10.9 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 (Th) 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 (REESN) 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.  相似文献   

9.
The Upper Triassic Chang 6 sandstone, an important exploration target in the Ordos Basin, is a typical tight oil reservoir. Reservoir quality is a critical factor for tight oil exploration. Based on thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), stable isotopes, and fluid inclusions, the diagenetic processes and their impact on the reservoir quality of the Chang 6 sandstones in the Zhenjing area were quantitatively analysed. The initial porosity of the Chang 6 sandstones is 39.2%, as calculated from point counting and grain size analysis. Mechanical and chemical compaction are the dominant processes for the destruction of pore spaces, leading to a porosity reduction of 14.2%–20.2% during progressive burial. The porosity continually decreased from 4.3% to 12.4% due to carbonate cementation, quartz overgrowth and clay mineral precipitation. Diagenetic processes were influenced by grain size, sorting and mineral compositions. Evaluation of petrographic observations indicates that different extents of compaction and calcite cementation are responsible for the formation of high-porosity and low-porosity reservoirs. Secondary porosity formed due to the burial dissolution of feldspar, rock fragments and laumontite in the Chang 6 sandstones. However, in a relatively closed geochemical system, products of dissolution cannot be transported away over a long distance. As a result, they precipitated in nearby pores and pore throats. In addition, quantitative calculations showed that the dissolution and associated precipitation of products of dissolution were nearly balanced. Consequently, the total porosity of the Chang 6 sandstones increased slightly due to burial dissolution, but the permeability decreased significantly because of the occlusion of pore throats by the dissolution-associated precipitation of authigenic minerals. Therefore, the limited increase in net-porosity from dissolution, combined with intense compaction and cementation, account for the low permeability and strong heterogeneity in the Chang 6 sandstones in the Zhenjing area.  相似文献   

10.
Tight grainstones, although widespread throughout the Lower Triassic Feixianguan Formation in the Sichuan Basin, have received little attention, in part, due to their lower porosity and greater heterogeneity relative to their dolostone counterparts. Based on data from cores and thin sections, as well as petrophysical properties, the Feixianguan grainstones, representing a major gas reservoir in the Jiannan gas field were systemically analysed to better understand porosity evolution in tight carbonates that have experienced original oil accumulation and subsequent thermal cracking during progressive burial. The grainstones were divided into two types according to whether pyrobitumen was present, and their porosity evolutions were quantitatively reconstructed. Taking 40% as the original porosity, the grainstones without pyrobitumen, which were ineffective palaeo-oil reservoirs, lost 21.94% and 3.13% of their porosities through marine and burial calcite cementation, respectively, and 13.34% by compaction, and have a current porosity of 1.59%, thus allowing them to serve as major present-day gas reservoirs. Comparatively, pyrobitumen-bearing grainstones, which were once palaeo-oil reservoirs, lost 23.96% and 2.36% of their porosities through marine and burial calcite cementation, respectively; 11.4% by compaction, and 1.44% by pyrobitumen and have a current porosity of 0.84%, thus making them ineffective gas reservoirs. This study provides a quantitative understanding of the close association between porosity evolution and reservoir effectiveness for the palaeo-oil charge and present-day gas accumulation with respect to diagenetic history, which is useful for the future exploration in tight gas limestone reservoirs.  相似文献   

11.
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12.
The Wufeng-Longmaxi organic-rich shales host the largest shale gas fields of China. This study examines sealed fractures within core samples of the Wufeng-Longmaxi shales in the Jiaoshiba shale gas field in order to understand the development of overpressures (in terms of magnitude, timing and burial) in Wufeng-Longmaxi shales and thus the causes of present-day overpressure in these Paleozoic shale formations as well as in all gas shales. Quartz and calcite fracture cements from the Wufeng-Longmaxi shale intervals in four wells at depth intervals between 2253.89 m and 3046.60 m were investigated, and the fluid composition, temperature, and pressure during natural fracture cementation determined using an integrated approach consisting of petrography, Raman spectroscopy and microthermometry. Many crystals in fracture cements were found to contain methane inclusions only, and aqueous two-phase inclusions were consistently observed alongside methane inclusions in all cement samples, indicating that fluid inclusions trapped during fracture cementation are saturated with a methane hydrocarbon fluid. Homogenization temperatures of methane-saturated aqueous inclusions provide trends in trapping temperatures that Th values concentrate in the range of 198.5 °C–229.9 °C, 196.2 °C-221.7 °C for quartz and calcite, respectively. Pore-fluid pressures of 91.8–139.4 MPa for methane inclusions, calculated using the Raman shift of C-H symmetric stretching (v1) band of methane and equations of state for supercritical methane, indicate fluid inclusions trapped at near-lithostatic pressures. High trapping temperature and overpressure conditions in fluid inclusions represent a state of temperature and overpressure of Wufeng-Longmaxi shales at maximum burial and the early stage of the Yanshanian uplift, which can provide a key evidence for understanding the formation and evolution of overpressure. Our results demonstrate that the main cause of present-day overpressure in shale gas deposits is actually the preservation of moderate-high overpressure developed as a result of gas generation at maximum burial depths.  相似文献   

13.
The mesogenetic dissolution is well developed in the middle Ordovician Yijianfang formation (O2yj) limestone, and the dissolution pores are very important for petroleum accumulation in the south slope area of the Tahe oilfield which lies in the north of the Tarim basin, northwestern China. Mottled, dotted or laminar dissolution can be observed in the O2yj limestone. Under microscope, the grains, lime matrix and all stages of calcite cements (including oil-inclusion-bearing blocky calcite cements) can all be found dissolved ubiquitously. The stylolites in the limestone were enlarged and rounded because of dissolution. Some dolomite rhombs, precipitated along stylolites in burial environment, were found dissolved as well. The dissolution of the blocky calcite cements and dolomite rhombs and the enlarging of stylolites demonstrate that the dissolution took place in the mesogenetic environment. Concentration of trace elements, including REEs, of the eroded part of the O2yj limestone is intermediate between that of the uneroded part and that of the underlying lower Ordovician limestone hydrocarbon source rocks. Both δ13CPDB and δ18OPDB values of the eroded part are less than those of the uneroded part, respectively. The geochemical characteristics indicate that the eroding fluids are hydrocarbon-bearing fluids coming from the underlying hydrocarbon source rocks.  相似文献   

14.
Significant volumes of the known hydrocarbon reserves are found in carbonate rocks, many of these dolomitized. The spatial distribution of diagenesis on these rocks is one of the main challenges in oil reservoir modeling. Reactive transport models can be a powerful tool to understand the active diagenetic processes and their effects on the quality of these reservoirs. In this study it was used, for the first time, the CMG-GEM simulator to model diagenetic evolution of a carbonate sequence, subjected to compaction-driven and geothermal flow in a simulated period of 200 thousand years. It was simulated carbonate cementation, dolomitization and dissolution, with and without presence of faults. Among the analyzed variables, the volume of circulating fluid was the most important factor. For both mechanisms, flow simulated velocities obtained had magnitudes smaller than 10−6 m/day. Diagenesis was insignificant for these low speeds at simulated time interval. Only dolomitized facies presented relevant diagenesis in form of calcite dissolution and dolomite precipitation. Simulations with flow rates of 1 m/day revealed a considerable increase in observed diagenesis, especially in carbonate cementation and in porosity enhancement. Diagenesis was more pronounced in more permeable sediments, highlighting the role of fluid flow in diagenetic reactions. Relative dissolution was greatly reduced during simulations performed with absence of dolomite and dolomitization reactions. The presence of faults strongly influences spatial distribution of diagenesis, especially relatively to dissolution. More permeable facies were more dissolved near fault, decreasing with increasing distance. Low permeability facies, as mudstones, are not dissolved, even near fault. Spatial distribution of diagenesis would then be dependent mainly on the quality of original pore structure, of fault presence and mineral composition of rock.  相似文献   

15.
Marine dolostones of Carboniferous Huanglong Formation constitute major gas reservoir rocks in eastern Sichuan Basin. However, the investigation with respect to sources of dolomitizing and diagenetic fluids is relatively underexplored. The current study attempts to investigate the REE characteristics of dolomites using seawater normalization standard, and therefore discusses the origins of dolomitizing and diagenetic fluids, on the basis of continuous 47.33-m-long core samples from the second member of Huanglong Formation (C2h2) in eastern Sichuan Basin. Low Th, Sc, and Hf concentrations (0.791 × 10−6, 4.751 × 10−6, and 0.214 × 10−6, respectively), random correlation between total REE concentration (ΣREE) and Fe or Mn abundance, and seawater-like Y/Ho ratios (mean value of 45.612) indicate that the carbonate samples are valid for REE analysis. Based on petrographic characteristics, four dolomite types are identified, including micritic-sized dolomite (type Dol-1), fine-to medium-sized dolomite (type Dol-2), medium-to coarse-sized dolomite (type Dol-3), and coarse-to giant-sized saddle dolomite (type Dol-4). Dol-1 dolomites, characterized by positive Ce anomaly (mean value of 6.398), light REE (LREE) enrichment, and heavy REE (HREE) depletion with mean LREE/HREE ratio of 12.657, show micritic calcite-like REE patterns, indicating seawater origin of their dolomitizing fluids. Dol-1 dolomites were formed in sabkha environment whereas the dolomitizing fluids originated from evaporative brine water due to their micritic crystal sizes and tight lithology. Dol-2 dolomites, particularly subtype Dol-2a barely developing vuggy porosity, also show micritic calcite-like REE patterns, suggesting their dolomitizing fluids were seawater or seawater-derived fluids. This inference is confirmed by low Fe and Mn concentrations, which range from 651 μg/g to 1018 μg/g (mean value of 863 μg/g) and 65 μg/g to 167 μg/g (mean value of 105 μg/g), respectively, whereas homogenization temperatures (Th, mean value of 103 °C) indicate that Dol-2 dolomites were formed under burial environment. Dol-3 dolomites, in form of cements of Dol-2 dolomites, show similar REE patterns to their host minerals (i.e., Dol-2 dolomites), indicating their parent source was possibly derived from Dol-2 dolomites. Dol-3 dolomites have high Fe and Mn concentrations with mean values of 3346 μg/g (ranging from 2897 μg/g to 3856 μg/g) and 236 μg/g (ranging from 178 μg/g to 287 μg/g), respectively, indicating the involvement of meteoric water. Meanwhile, it confirms that the dissolution in Dol-2 dolomites was caused by meteoric water leaching. Positive Eu anomalies (mean value of 1.406) in Dol-4 dolomites, coupled with high homogenization temperatures (mean value of 314 °C), suggest that Dol-4 dolomites precipitated from hydrothermal fluids. High Fe and Mn concentrations (mean values of 2521 μg/g and 193 μg/g, respectively) in Dol-4 dolomites likely results from interactions of hydrothermal fluids with deep burial clastic rocks.  相似文献   

16.
The Tournasian age Pekisko carbonates in the Normandville Field (northwestern Alberta) form waulsortian-like, bryozoan/crinoid mounds that developed in fairly deep, low energy, cool water systems, close to the ramp margin. Three main depositional environments occur: (1) crinoidal apron with wackestone, grainstone and floatstone facies; (2) mound flank with grainstone, wackestone, packstone and floatstone facies dipping 35°; and (3) bryozoan mound core, composed of rudstone and floatstone facies with fenestrate bryozoa, minor crinoids and carbonate mud. Local highs due to fault-bounded blocks, created from the collapse of the Devonian Peace River High, may have controlled the location of mound nucleation.Diagenesis of the bryozoan/crinoid mounds included calcite cementation, compaction, dolomitization, silicification, and hydrocarbon emplacement events. The mound core facies contains submarine fascicular optic calcite and bladed/prismatic calcite cements, and later ferroan, brightly luminescent, pore-filling blocky spar cement. The crinoid apron facies contains syntaxial cement associated with crinoids, and the ferroan blocky spar cement. The mounds are dominantly limestone; however, in one well, dolomite dominates the lower section. Four types of dolomite have been identified: partial replacive; chemical-compaction-related, pervasive dolomite and saddle dolomite cement. All dolomites are non-stoichiometric (CaCO3 mole% 56.6–62.6). The partial, zoned replacive dolomite replaces micrite and syntaxial rim calcite in mound flank and crinoid apron facies. The chemical compaction-related dolomite is found along dissolution seams and stylolites and has similar CL characteristics to the replacive dolomite. The pervasive dolomite is fabric destructive and has dull cores and bright rims in CL. Saddle dolomite (0.15 mm) has brightly-luminescent, concentric zoning and occurs in vugs and fossil pore spaces.Chemical and isotopic analysis of the bryozoan/crinoid mounds indicate that the original marine signatures in micrite, early cements, some crinoids and brachiopods have been preserved. However, carbon isotopic values for some crinoids, matrix and dolomite show more positive values compared to known Mississippian carbonate values. Recrystallization during shallow burial has reset the oxygen isotopic composition of some crinoids and micrite. Oxygen and carbon isotopic compositions of most dolomites overlap with altered crinoids and early calcite cements. However, saddle dolomites have lighter δ18O values, similar to saddle dolomites from the Devonian Wabamun Group in this area. The isotopic variations in later ferroan calcite cements show an inverted-J trend, possibly due to variable amounts of water-rock interaction. While the Sr-isotopic ratio of submarine calcite cement coincides with that of Mississippian seawater, the later ferroan calcite cement is more radiogenic, indicating a different source of fluids.  相似文献   

17.
The Early Jurassic dolomitized carbonates in the Venetian Alp, represent a surface analogue of the hydrocarbon exploration targets in Adriatic offshore and Po Plain, Italy. Dolomitization affected the carbonate platform of Monte Zugna Formation (Lower Jurassic) and the Neptunian dikes breccia in the pelagic Maiolica Formation (Uppermost Jurassic–Lower Cretaceous) improving the poro-perm characteristics. Petrography, stable isotope, strontium isotope ratio, trace element and fluid inclusion analyses were carried out on samples from the Monte Grappa Anticline, which is the direct analogue for subsurface. The petrographic analyses showed a first pervasive, replacement dolomitization phase (D1) followed by volumetrically less important dolomite cement precipitation phases (D2, D3, DS). The same, quite wide range of oxygen isotope (?9 to ?2‰ V-PDB) is observed in all dolomite types. The δ13C range is in the positive field of marine derived carbonate (from +0.5 to +3.2‰ PDB). The trace element analysis showed a slight enrichment in Fe and Mn contents in the Monte Zugna dolostones with respect the original limestone. The same dolomite precipitation temperature (up to 105 °C Th) was observed in the replacement and cement dolomites, suggesting a unique dolomitization event. This temperature, largely higher than the maximum burial temperature (about 50 °C), supports a hydrothermal origin of the dolomitizing fluids, which had a seawater to brackish composition. The data collected suggest a hydrothermal dolomitization occurring during to the South Alpine thrusting according to the “squeegee model”. The interpretation is consistent with the dolomitization model proposed for similar Jurassic successions in the Central Southern Alps. This study indicates that the deformed foreland and thrust fold belts carbonates in Po Plain and Adriatic offshore are suitable to be dolomitized, and therefore reflect an efficient hydrocarbon exploration play.  相似文献   

18.
The Zagros-Taurus fold and thrust belt hosts a prolific hydrocarbon system. Most hydrocarbon reserves are stored in naturally fractured reservoirs and such fracture systems can therefore have a significant impact on reservoir performance. Fractures are one of the most important paths for fluid flow in carbonate reservoirs, and industrial geoscientists and engineers therefore need to understand and study fracture patterns in order to optimise hydrocarbon production. The observed fracture patterns in outcrops may have implications on fluid flow and reservoir modelling in subsurface reservoirs, and we have therefore undertaken a case study of fracturing associated with regional folding in Iraqi Kurdistan. In this area, some exploration wells currently target Upper Triassic dolostones (Kurra Chine Formation) and/or Lower Jurassic limestones and dolomitised limestones (Sehkaniyan Formation). In both units hydrocarbon production comes mainly from secondary porosity created by dolomitisation, dissolution and fracturing. Both formations have undergone multiple phases of deformation associated with burial, uplift, folding and thrusting. We investigate some fracture pattern characteristics and some petrophysical properties of these units using selected outcrops around the Gara, Ora and Ranya anticlines that form folds directly traceable for 25–70 km. Our outcrop data is compared with subsurface fracture and petrophysical datasets reported from wells in the nearby Shaikhan and Swara Tika Fields. The 1-2-3D fracture attributes collected from outcrops are fracture orientation, type, spacing, intensity, length and cross-cutting and abutting relationships. Fracture orientations show a clear relationship to the local fold axis in both the outcrop and subsurface, although in some cases they appear to relate more to the present day in-situ maximum horizontal stress direction or local strike-slip faulting. Three stages of fracturing are proposed: pre-folding, early-folding and post-folding fractures. In addition, we report petrophysical properties - porosity, permeability and acoustic velocity of both the Kurra Chine and Sehkaniyan formations in relation to their structural position within folds and faults and stratigraphic level. The highest porosities and permeabilities are recorded in the hinges and backlimbs of the Gara Anticline. The best reservoir quality (highest porosity and permeability) is often found in areas associated with replacement dolomite i.e. solution vugs and intercrystalline porosity. The Kurra Chine Formation displays similar trends in velocity-porosity data at both outcrop and the subsurface. However, the Sehkaniyan Formation displays lower acoustic velocity for a given porosity at outcrop compared to the subsurface.  相似文献   

19.
The transformation of depositional lime mud to microporous micrite has been the subject of several important papers recently in response to the recognition that micropores are important to the production of carbonate hydrocarbon reservoirs. The origin of micrite has generally been described as a micro dissolution and reprecipitation process (often referred to as Ostwald ripening), with nanometer-sized depositional particles being dissolved and larger crystals (micrite) averaging 2 μm in diameter being precipitated. These conclusions were tested by detailed scanning electron microscope (SEM) observations of micrite and minimicrite crystals found in the mid-Pliocene to upper Miocene section of the Clino core taken on the western edge of the Bahama Bank. Minimicrite in this data set is shown to be composed of both aragonite and calcite with calcite being the dominate mineral. In addition, micrite crystals are composed of cemented nanometer-sized calcite crystals and are not individually precipitated calcite crystals. As a result, the faces of the micrite are anhedral and knobby in appearance rather than being smooth, euhedral crystal faces. Extensive size measurements could find no size selectivity in the dissolution of the calcite minimicrite, indicating that the Ostwald ripening process is not active. Aragonite and calcite crystals are dissolved and some calcite crystals act as nuclei for the precipitation of the dissolved carbonate. The origin of the micropores is also debated. Some authors call upon a dissolution event to increase porosity of a partially cemented micrite, based largely on the anhedral nature of the micrite. Others conclude that porosity is originally inherited from the deposition lime mud and that porosity is lost by overgrowth cementation, which results in euhedral micrite crystals. The observations presented here show that anhedral crystals are due to the inclusion of nanometer calcite crystals rather than to dissolution of euhedral crystals. Lastly, these micrite crystals are formed by calcite and aragonite sediment precipitated from an aragonitic sea, disproving the assertion of some authors that porous micrite only forms from sediments deposited in calcitic seas.  相似文献   

20.
Anomalously high porosities up to 30% at burial depth of >3000 m along with varying amounts and types of carbonate cements occur in the fluvial channel sandstone facies of the Triassic Skagerrak Formation, Central Graben, Norway. However, porosities of the Skagerrak Formation are lower in the Norwegian sector than in the UK sector. In this study, petrographic analysis, core examination, scanning electron microscopy, elemental mapping, carbon and oxygen isotope, fluid inclusion and microgeometry analysis are performed to determine the diagenesis and direct influence on reservoir quality, with particular focus on the role played by carbonate cementation. The sandstones are mainly fine-grained lithic-arkosic to sub-arkosic arenites and display a wide range of intergranular volumes (2.3%–43.7% with an average of 23.6%). Porosity loss is mainly due to compaction (av. 26.6%) with minor contribution from cementation (av. 12.1%). The carbonate cements are patchy in distribution (from trace to 20.7%) and appear as various types e.g. calcretes (i.e. calcareous concreted gravels), poikilitic sparite and sparry ferroan dolomite, and euhedral or/and aggregated ankerite/ferroan dolomite crystals. This study highlights the association of carbonate precipitation with the remobilisation of carbonate from intra-Skagerrak calcretes during early burial stage i.e. <500 m. During deeper burial, compaction is inhibited by carbonate cements, resulting high intergranular volume of up to 32% and 29% for fine- and medium-grained sandstones, respectively. Carbonate cement dissolution probably results from both meteoric water flow with CO2 during shallow burial, and organic CO2 and carboxylic acid during deep burial. The maximum intergranular volume enhanced by dissolution of early carbonate cements is calculated to 8% and 5% for fine- and medium-grained sandstones, respectively. Compaction continues to exert influence after dissolution of carbonate cements, which results in a loss of ∼6% intergranular volume for fine- and medium-grained sandstones. Reservoir quality of the Norwegian sector is poorer than that of the UK sector due to a lower coverage of clay mineral coats e.g. chlorite, later and deeper onset of pore fluid overpressure, lower solubility of carbonate compared to halite, and a higher matrix content.  相似文献   

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