Adjacent Mudstones Research Articles

Fluid evolution and related fluid–rock interactions of the Oligocene Zhuhai sandstones in the Baiyun Sag, northern margin of the South China Sea

Pore fluids control the diagenetic processes and storage spaces of deep clastic rock reservoirs and have become a major area of interest within the fields of sedimentology and petroleum geology. This paper aims to relate the diagenetic processes of the Oligocene Zhuhai sandstones in the Baiyun Sag to pore fluids varying with burial depth. The types and distribution patterns of authigenic minerals are investigated through analysis of petrographic, mineralogical, and geochemical features to illustrate the origin and flow patterns of pore fluids and their influences on reservoir diagenesis. Strong cementation of eogenetic carbonate cement near the sandstone–mudstone interface was a consequence of material migration from adjacent mudstones on a large scale. The pore fluids were mainly affected by microbial methanogenesis and carbonate mineral dissolution in adjacent mudstones during eogenesis. The pore fluids were diffusively transported in a relatively open geochemical system within a local range. Support for this model is provided by the heavier stable isotopic values present in eogenetic calcite and dolomite. Feldspar dissolution during early mesogenesis was spatially accompanied by the precipitation of authigenic quartz and ferroan carbonate cement. Pore fluids in this period were rich in organic acids and CO2, and their migration mechanism was diffusive transport. The obviously lighter carbon and oxygen isotopic compositions of the ferroan calcite support this inference. During late mesogenesis, the input of deep hydrothermal fluid might have been partly responsible for the precipitation of ankerite, barite and authigenic albite. Oil charging may have inhibited carbonate cementation and compaction, accordingly preserving porosity, and together with authigenic kaolinite, might have promoted the transition of the reservoir from water wet to oil wet to the benefit of oil entrapment. The findings reported here shed new light on the evaluation and prediction of sandstone reservoirs that have experienced multiple periods of fluid flow.

Impact of coal evolution on formation of tight sandstone reservoirs: A case study in the Daniudi gas field, Ordos Basin, China

Tight sandstone gas in coal-bearing strata has become an important unconventional gas worldwide. This research aims at understanding the impacts of coal evolution on diagenesis and reservoir quality of sandstones by means of thin section, cathode luminescence (CL), scanning electron microscope (SEM), stable isotope analysis, and fluid inclusions. The results show that carbonate cement was the main type of cement developed in tight sandstone reservoirs, of which the carbonate ions were jointly provided by coal layers and reaction in adjacent mudstones. For sandstones close to coal layers, their carbonate ions were mainly controlled by coal evolution and there was various carbonate cement developed due to cations supplied by seawater and the intense dissolution of volcanic fragments and feldspars. Combined with coal thermal simulation and burial history, it implies that at different maturity stages of coal evolution, its impact on sandstone diagenesis was different. In the early stage, the main product was CO2, which caused the dissolution of early calcite and promoted intense compaction. In the mature stage, CO2 and other hydrocarbon gases were released, resulting in more dissolution and silica cementation. In the over-mature stage, the main product was methane, and CO2 that did not spill out preserved by forming carbonate cement. The coal evolution had a strong impact on the reservoir quality of sandstone with large grain sizes, but little effect on medium- and fine-grained sandstones. High porosity and low permeability reservoirs were usually formed in small conglomerates and coarse-grained sandstones away from coal layers. While low porosity and high permeability reservoirs were distributed close to coal layers. This study aids in understanding the formation mechanism of tight sandstone reservoirs in coal measures and provides theoretic support for further exploration.

Controls of diagenesis on the quality of shallowly buried terrestrial coarse-grained clastic reservoirs: A case study of the Eocene Shahejie Formation in the Damintun Sag, Bohai Bay Basin, Eastern China

A typical shallowly buried (800–2000 m burial depth) coarse-clastic, nonmarine, fan-deltaic reservoir is well developed in the Eocene Shahejie Formation, Damintun Sag, Bohai Bay Basin, China. In this study, diagenesis and its control on the reservoir quality of fan-deltaic sandstones and conglomerates in the Shahejie Formation were investigated in detail by petrographic and geochemical analyses, including cathodoluminescence, X-ray diffraction, scanning electron microscopy, electron probe microanalyses and X-ray fluorescence. The reservoir sandstones and conglomerates mainly consist of moderately sorted feldspathic litharenite, which has undergone various diagenetic processes such as mechanical compaction, cementation, and dissolution, and are currently in the eodiagenesis stage with porosity and permeability averaging 21.56% and 435.2 mD, respectively. Mechanical compaction and cementation caused an ∼45% reduction in the original reservoir porosity, especially the former, which exerted a more significant influence. In regard to cementation, the late calcite that formed at the mudstone-sandstone interface is more destructive and enhances reservoir heterogeneity, and its source material is believed to be primarily derived from the adjacent mudstones in conjunction with oil and gas charging. Feldspar dissolution plays a limited constructive role in reservoir properties by creating ∼10% secondary porosity and changing reservoir wettability to oil wet through the formation of authigenic kaolinite. As a result, massive primary pores (∼90% of the total pores) in the shallowly buried sandstones and conglomerates in the Eocene Shahejie Formation are still preserved. This systematic study is expected to be applicable in a general way to other shallowly buried terrestrial clastic reservoir systems.

The influence of diagenetic heterogeneity on tight-reservoir properties in the Upper Triassic Yanchang Formation, Southeastern Ordos Basin, China

ABSTRACT The Chang 7–8 sections of Yanchang Formation in the Ordos Basin are dominated by lacustrine tight sandstones but characterized by high hydrocarbon production. This setting provided an opportunity to study reservoir characteristics and diagenetic processes of tight sandstones, to facilitate future oil exploration. In this study, it was found that reservoir qualities were mainly controlled by the diagenetic heterogeneity at different parts of sandstones, based on a comprehensive analysis of thin sections, scanning electron microscopy (SEM), X-ray diffraction (XRD), pressure-controlled mercury injection, X-ray computed tomography (XCT), and well log data. Carbonate cements tend to occur at the edges of sandstone bodies. Sandstone layers with a distance less than 0.5 m from the sandstone–mudstone interface, or with a thickness of less than 1.5 m, were rich in carbonate cements (carbonate content was more than 15%). Lower porosity (less than 4%) and permeability (less than 0.01 mD) trend to distribute in sandstones that have higher content of carbonate cements. The source of carbonate cements was most likely from adjacent mudstones or from the dissolution of unstable grains. Samples collected from the center of sandstone layers have higher porosity, pore connectivity, and permeability but with low carbonate cement content. Hydrocarbon accumulation was facilitated through vertical fractures between the layers. The dissolution of feldspar and lithic fragments by organic acid associated with oil charging improved reservoir properties in the center of sandstone layers, and generated material for carbonate cement precipitation at the edge of sandstone layers. The results of this study demonstrated that the dominance of different diagenetic processes led to a reduction of reservoir quality at the edge of sandstone layers but an increase in the center of sandstone layers. This research offered a new perspective on the study of reservoir properties and the diagenesis mechanism of tight sandstones, which could be conducive to tight oil exploration and development.

Sources of Ca2+ in the major carbonate cements in Eocene sandstones and conglomerates: Evidence from Sr isotopes, Sr/Ca ratios, and rare-earth elements

Different sources of calcium have important effects on the formation and distribution of carbonate cements. On the basis of identifying all possible sources of calcium, comprehensive quantitative analyses of Sr, C, and O isotopic values and trace elements (including rare-earth elements) were conducted to determine the Ca2+ sources and their changes in the same type of carbonate cements at different vertical positions in the same reservoirs. Ferroan calcite and ankerite were the major types of carbonate cements. Ca2+ in ferroan carbonate cements in the sandstones near the mudstone-sandstone (M-S) interfaces was derived primarily from diagenetic fluids mixed with Ca2+ originating from the transformation of smectite to illite and from original sedimentary water in the adjacent mudstones. However, Ca2+ in the ferroan carbonate cements in the sandstones away from the M-S interfaces originated from the transformation of smectite to illite, the dissolution of carbonate minerals, and original sedimentary water in source rocks. The gradual change of Ca source of the same type of ferroan carbonate cements indicates the diversity of migration direction of diagenetic paleo-fluid in the same period. During the transformation of smectite to illite, concentration gradients were created from mudstones to sandstones. Ca2+, Mg2+, Fe2+, and other cations in the mudstones diffused to the adjacent sandstones and provided sources of ferroan carbonate cements at the edge of the sandstones. Pore water with Ca2+, Mg2+, Fe2+, CO32−, and other cations in the source rocks was collectively charged into sandstones during oil emplacement and promoted the precipitation of ferroan carbonate cements in residual pore water. Due to oil emplacement and material supplied by the adjacent mudstones, the content of ferroan carbonate cements in the sandstones was lower, and the reservoir porosity was higher at a greater distance from the M-S interfaces. However, in thick-bedded sandstones, due to lack of material supply from the adjacent mudstones, Ca2+, Mg2+, Fe2+, and CO32− in the ferroan carbonate cements were mainly derived from source rocks. As a result, no significant changes were observed in the content of ferroan carbonate cements and reservoir porosity in the vertical direction.

Effects of sedimentary processes and diagenesis on reservoir quality of submarine lobes of the Huangliu Formation in the Yinggehai Basin, China

Submarine lobe deposits of the upper Miocene Huangliu Formation in the Yinggehai Basin, characterised by high-temperature (132.4–141.2 °C), high overpressure (1.69–1.99), and inorganic CO2 accumulations, offer an excellent opportunity to investigate how reservoir quality is linked to sedimentary processes and diagenesis. This study examines the control on reservoir quality of submarine lobes using petrographic, geochemical, drilling test, and measured petrophysical data. Lobe axis deposits contain high-density turbidites (HDTs) that exhibit good reservoir quality, a higher degree of sandstone amalgamation, and larger grain sizes and pore-throat radii. The lobe off-axis deposits are composed of HDTs and low-density turbidites (LDTs) with moderate reservoir quality. In contrast, the lobe fringe deposits mainly comprising muddy debrites have the lowest reservoir quality. Sedimentary processes macroscopically controlled the initial grain size segregation, variation of textural properties, and reservoir quality throughout the submarine lobes. Flow transformation from turbidity currents in the lobe axis areas into muddy debris flows in the lobe fringe areas led to the high clay content of lobe fringe deposits, due to the incorporation of sediment eroded from the muddy seafloor. Mechanical compaction is the major diagenetic factor reducing reservoir properties of sandstones in the lobe axis and lobe off-axis positions. Calcite and ferrocalcite cements in the sandstones from the CO2-poor DF-B gas field were linked with thermal decarboxylation of organic matter in the adjacent mudstones. In contrast, the diagenetic processes in the CO2-rich DF-A gas field were more likely to be affected by inorganic CO2 accumulations. As a whole, the CO2-water-rock reactions in the CO2-rich DF-A area can not only lead to the precipitation of late dolomite and ankerite, and formation of authigenic clay minerals, but also cause intense dissolution of unstable compositions, resulting in an insignificant increase in porosity. In addition, the high-overpressure in both gas fields has effectively protected the primary porosity by reducing the effective stress exerted on the detrital grains. This study has implications for the assessment of reservoir potential in carbon sequestration and storage, and hydrocarbon exploration and production.

Carbonate cementation patterns, potential mass transfer, and implications for reservoir heterogeneity in Eocene tight-oil sandstones, Dongying depression, Bohai Bay Basin, China: Evidence from petrology, geochemistry, and numerical modeling

This paper investigates transport mechanisms involving carbonate cementation in Eocene, tight-oil sandstones in Bohai Bay Basin, China, to determine potential mass transfer between adjacent mudstones and sandstones. Evidence from petrology, geochemistry, and numerical modeling suggests two generations of carbonate cementation: (1) early nonferroan calcite (formed at 28°C–41°C) and dolomite (formed at 45°C–63°C); and (2) later ferroan calcite (formed at 105°C–124°C) and ankerite (formed at 101°C–137°C). Based on a one-dimensional model for a coupled sandstone–mudstone system under low and high temperatures, different distribution patterns of carbonate cements reflect episodic concentration gradients that led to diffusive transport of bicarbonate species during progressive burial. Firstly, extensive precipitation of early nonferroan calcite followed by dolomite at or near mudstone–sandstone contacts resulted from initial concentration gradients related to different compositions in primary mineral assemblages. Secondly, introduction of aqueous CO2 from adjacent mudstones into sandstones resulted in dissolution of early nonferroan carbonates and led to diffusive transport of bicarbonate species. These bicarbonate species were incorporated with Fe2+ and subsequently reprecipitated as ferroan carbonate minerals at distances greater than 2 m (>6.6 ft) from sandstone–mudstone contacts. Therefore, short-distance diffusive transport is inferred to have been the predominant transport mechanism associated with carbonate cementation. Large-scale mass transfer between sandstones and adjacent mudstones occurred in a relatively open geochemical system on a very local scale. Numerical model results show that low porosity zones (2.6%–5.1%) exhibit coherence with high abundances of carbonate cements (13.9%–21.2%). Tightly cemented intervals were created by different generations of carbonate cementation and resulted in destruction of sandstone reservoir porosity.

Mass transfer between sandstones and interbedded mudstones: Impact on petroleum charge, Bohai Bay Basin, China

Abstract The Permo-Carboniferous sandstones in the Gubei area, Bohai Bay Basin, are reservoirs for large accumulations of natural gas. The natural gas accumulations only occur in the sandstone beds thicker than 1.9 m. Moreover, the maximum porosity of every bed correlates positively with bed thickness up to 2.0 m and for thicker beds porosity is uniform. Porosity transitional zones developed at the top and bottom of each bed, with mean thicknesses of 1.25 m and 0.75 m, respectively. Porosity shows a positive correlation with the distance to the sandstone/mudstone contact in the zones. Interpretations based upon an extensive petrographic and geochemical database indicate that the sandstones experienced a mass fluid input from the adjacent mudstones during the early diagenesis. The infiltration resulted in extensive clay coats and pore-filling cements in sandstones, which were effective for inhibiting dissolution of grains during subsequent diagenesis process. The mass introduction only affected the marginal parts of the sandstones within 1.25 m of the top and 0.75 m of the bottom of every bed, causing thin sandstone beds with thickness of approximately 2 m to be tightly cemented totally. Thus the central parts of each (thicker) beds became preferential sites for the natural gas accumulation. The differential levels of cementation in thin and thick sandstone beds observed here has significant implications for exploration of similar interbedded sandstone and shale sequences elsewhere including shale gas targets.

Small- and large- scale soft-sediment deformations in a Triassic lacustrine delta caused by overloading and seismicity in the Ordos Basin, central China

Abstract The instability of an Upper Triassic lacustrine deltaic system, in the southwestern Ordos Basin, central China, is examined based mainly on detailed measurements and descriptions of core data. Nine lithofacies associations are identified, including undeformed and deformed channel deposits, sandy and muddy slumps, sandy debrites, sandy dykes, undeformed and deformed fringe silty deposits, and muddy deposits. Quantification of the vertical and horizontal spatial distribution of these sediments reveals the deformed sediments can comprise more than one third of the entire cored interval in more than half of the wells, indicating the significance of soft-sediment deformation structures as essential components of this deltaic system. A depositional model is constructed, which highlights the location of deformed and remobilized sediments and their relationships with undeformed sediments. In the proximal part of the delta, the undeformed and deformed channel deposits and sandy slumps dominate the sandy sediments, which are interbedded to form thick amalgamated sandstones. In areas distant from these massive sandstones, undeformed and deformed fringe fine-grained deposits are well developed, which could generate muddy slumps. In the distal part of the delta, besides undeformed and deformed fringe fine-grained deposits, sandy debrites are present as isolated sandbodies. Large-scale sandy dykes formed between thick sandstones and adjacent mudstones. Two possible trigger mechanisms for initial deformation development are identified - sediment overloading induced by sudden deposition of remobilized sediments and seismicity which caused large-scale remobilization in the study area. The high percentage of soft-sediment deformation structures in this delta influences the reservoir heterogeneity of the three types of sandstones (undeformed channel deposits, sandy slumps and sandy debrites). Porosity-permeability analysis reveals that reservoir quality of these three types varies significantly, and thus distinguishing deformed sediments from undeformed deltaic sediments is essential for hydrocarbon development in this area.

Petroleum potential of the Upper Jurassic Hareelv Formation, Jameson Land, East Greenland

The marine, mudstone-dominated Hareelv Formation (Upper Jurassic) of Jameson Land, East Greenland is a representative of the widespread Kimmeridge Clay Formation equivalents, sensu lato, known from the greater North Atlantic region, western Siberia and basins off eastern Canada. These deposits constitute the most important petroleum source-rock succession of the region. The present study reports petroleum geochemical data from the 233.8 m thick succession penetrated by the fully cored Blokelv-1 borehole, and includes supplementary data from outcrop samples and other boreholes in Jameson Land. The succession consists of basinal mudstone intercalated with a significant proportion of gravity-flow sandstones, both in situ and remobilised as injectites. The mudstones are generally rich in organic carbon with values of TOC reaching nearly 19 wt% and high pyrolysis yields reaching values of S2 up to nearly 43 kg HC/ton. Hydrogen Indices are up to 363. The data presented herein demonstrate that weathering of abundant pyritic sulfur adversely affects the petroleum potential of the kerogen in outcrop samples. The succession is thermally immature to early mature, except where intrusions have locally heated adjacent mudstones. The documentation of rich gas/oil-prone Upper Jurassic successions in Jameson Land is important for the assessment of the regional petroleum potential, including the North-East Greenland continental shelf.

Tight oil sandstones in Upper Triassic Yanchang Formation, Ordos Basin, N. China: Reservoir quality destruction in a closed diagenetic system

AbstractAn investigation of the Triassic Yanchang Formation, Ordos Basin, N. China, revealed that the diagenesis and quality of tight oil sandstone reservoirs (with an average porosity of 9.83% and an average permeability of 0.96 mD) were controlled by a closed diagenetic system. The carbonate cements observed in the sandstone were derived from decarboxylation of organic matter that occurred in the adjacent mudstones. These reactions supplied CO32−, which reacted with cations derived from grain dissolution in the sandstones. The average size of the diagenetic geochemical system with respect to carbonate cements was small (<6 × 10−2 m3), comprising sandstone and its adjacent mudstone(s). The carbonate cements tend to concentrate in the marginal sandstone, which is taken to indicate that the flux of CO32− into the sandstones limited the quantity of carbonate precipitated. In addition, the mass is near balance between the amount of feldspar dissolution and its by‐products in the central sandstone (distance to the sandstone/mudstone interface is mainly more than 1 m), where the permeability of sandstone will present a decreasing trend with the increase of feldspar dissolution pores. The pore space of central sandstone will be just redistributed, with primary intergranular pores converting to feldspar dissolution pores and clay mineral micropores. Thus, the best part of the sandstone reservoirs tends to be the central part of sandstone. In particular, sandstones that are more than 2 m thick could be the potential hydrocarbon reservoirs because they retain the best porosity (average of 13.6%) and permeability (average of 1.8 mD). The results of our study provide an important guide for the exploration of tight oil sandstones in other petroliferous basins over the world.

Methane hydrate formation in thick sand reservoirs: 1. Short-range methane diffusion

We show with a comprehensive hydrate formation model that diffusion of dissolved methane along the local concentration gradient alone cannot transport enough methane to form the concentrated methane hydrates in thick (>= several m) marine sand reservoirs. In this model, methane is generated locally by biodegradation of organic matter in mudstones and diffused into the bounding sandstone where the methane hydrate solubility decreases abruptly and hydrate precipitates from the extra methane in water. Hydrate formed by local diffusion has peak concentrations at the top and base of the sandstone, and it decreases sharply toward the center; salinity is slightly elevated relative to seawater, and its gradient is negligible across the sandstone and adjacent mudstones; dissolved methane concentration decreases from the mudstones to the sandstone. Overpressure is generated in the sediment due to reduction of sediment permeability and volume expansion when hydrate replaces pore water. There is a shallow zone where pore pressure converges toward the lithostatic pressure and fracturing is possible. This study provides further insights into hydrate formation by local diffusion of dissolved methane. In addition, the numerical model we developed in this study fully couples the hydrate-liquid capillary effect, dynamic pore size change, and transient pore pressure-dependent sediment compaction with the multiphase (gas, liquid and hydrate) flow and multicomponent (methane, water and salt) transport. Our model not only predicts pore pressure, but also incorporates the effect of hydrate formation on overpressure generation and subsequent dissipation. These modeling approaches are now at a level of sophistication that we can start to distinguish what physical processes, of the several proposed, are viable explanations for observed hydrate deposits.

Fluid flow and related diagenetic processes in a rift basin: Evidence from the fourth member of the Eocene Shahejie Formation interval, Dongying depression, Bohai Bay Basin, China

The purpose of this paper is to relate diagenetic processes in deeply buried sandstones in the fourth member of the Eocene Shahejie Formation interval, Bohai Bay Basin, China, to pore-fluid flow changes with progressive burial. Based on petrographic, mineralogical, and geochemical analysis, distribution patterns of authigenic minerals are recognized that reflect (1) the sources and patterns of fluid flow and (2) fluid flow in an evolving open-to-closed system. Partial to extensive precipitation of calcite and dolomite at or near mudstone–sandstone contacts during eogenesis was a result of large-scale mass transfer between sandstones and adjacent mudstones. This process was driven by steep diffusion gradients from adjacent mudstones in a relatively open geochemical system on the local scale. Support for this model is provided by large sulfur isotope fractionation between framboidal pyrite and precursor gypsum. Dissolution of feldspar grains and dissolution of nonferroan carbonate cements during early mesogenesis are spatially associated with quartz and ferroan carbonate cementation, respectively. This process was related to organic carbon dioxide expelled from adjacent source rocks and indicates a relatively open system. During late mesogenesis, dissolution of evaporitic cements related to thermochemical sulfate reduction (TSR) generated ankerite and nodular pyrite cements in adjacent pores. A lack of sulfur isotope fractionation between parent anhydrite and late-stage, nodular pyrite during TSR supports a relatively closed fluid-flow system. Because the velocities of pore-fluid flow were low during mesogenesis, large-scale thermal convection and advection probably did not occur. Instead, diffusion over short distances is inferred as the predominant transport mechanism for dissolved solids that were precipitated as other phases either in situ or in adjacent pores.

Origin of carbonate cements with implications for petroleum reservoir in Eocene sandstones, northern Dongying depression, Bohai Bay basin, China

The Eocene Es4s interval is an important petroleum reservoir of sublacustrine fan dominated at the depths of 2500–4000 m in Dongying depression, Bohai Bay basin. Based on core observation, three types of carbonate-cemented beds have been identified and commonly contain ferroan calcite and ankerite predominantly and less calcite and dolomite. Precipitation temperatures range from 34.6 to 72.8℃ for calcite and dolomite cements, and from 110 to 153℃ for ferroan calcite and ankerite cements. The high δ13CPDB values (−0.65 to +5.59‰) for calcite and dolomite suggest that dissolved inorganic carbon, derived from methanogenic fermentation of organic matter in adjacent mudstones. The low δ13CPDB values (+1.04 to +3.29‰) for ferroan calcite and ankerite probably indicate a mixture of carbon derived from decarboxylation of organic acid as well as from the dissolution of early formed carbonate cements. High plug porosity is mainly developed at the central section of sandstones vertically and the porosity decreases sharply toward the top and base of the sandstones due to extensively carbonate-cemented beds. The carbonate-cemented beds varies from 0.02 to 0.5 m in thickness and might extend from tens to hundreds meters laterally. It could be served as fluid-flow barriers and seals for petroleum, and result in reservoir deterioration and significant heterogeneity.

Subsalt pressure prediction in the Miocene Mad Dog field, Gulf of Mexico

Sandstone pressures follow the hydrostatic gradient in Miocene strata of the Mad Dog field, deep-water Gulf of Mexico, whereas pore pressures in the adjacent mudstones track a trend from well to well that can be approximated by the total vertical stress gradient. The sandstone pressures within these strata are everywhere less than the bounding mudstone pore pressures, and the difference between them is proportional to the total vertical stress. The mudstone pressure is predicted from its porosity with an exponential porosity-versus-vertical effective stress relationship, where porosity is interpreted from wireline velocity. Sonic velocities in mudstones bounding the regional sandstones fall within a narrow range throughout the field from which we interpret their vertical effective stresses can be approximated as constant. We show how to predict sandstone and mudstone pore pressure in any offset well at Mad Dog given knowledge of the local total vertical stress. At Mad Dog, the approach is complicated by the extraordinary lateral changes in total vertical stress that are caused by changing bathymetry and the presence or absence of salt. A similar approach can be used in other subsalt fields. We suggest that pore pressures within mudstones can be systematically different from those of the nearby sandstones, and that this difference can be predicted. Well programs must ensure that the borehole pressure is not too low, which results in borehole closure in the mudstone intervals, and not too high, which can result in lost circulation to the reservoir intervals.

Fluidization and injection in the deep‐water sandstones of the Eocene Alba Formation (UK North Sea)

AbstractThe Nauchlan Member of the Late Eocene Alba Formation (UK North Sea) consists of a deep‐water channel fill that was extensively modified by post‐depositional sand remobilization and injection. Sandstone textures, facies associations and the geometry of the channel fill were affected. A suite of sand‐rich facies was produced by large‐scale fluidization and injection within the channel fill and above it. These facies, termed here unstratified facies, are characterized by the absence of stratification surfaces and by discordant relationships with bedding in the adjacent succession. They reflect variable degrees of disruption of the primary sedimentary structures caused by escaping pore fluid, the velocity of which is estimated at least in the order of 0·1 ms−1. Adjacent mudstones were severely disrupted by hydraulic fracturing, and fragments of fractured mudstone were incorporated into the fluidized sand. Average porosity was decreased in the sandstones affected by fluidization. Two main phases of sand injection are inferred to occur at different burial depths. A shallow burial phase (below 100 m) produced thin dykes with ptygmatic folds. The second phase occurred at the boundary between Eocene and Oligocene (≈ 300 m burial depth) and resulted in large‐scale tabular wing‐like dykes that project from the edges of the channel fill. The significant pore‐fluid overpressure, which was required to hydraulically fracture the thick mudstone seal and to fluidize the large volume of sand, was likely to be built up by static liquefaction of the source sand and was possibly enhanced by hydrocarbon gas influx.

Sequence-stratigraphical interpretation of organic facies variations in marine siliciclastic systems: general principles and application to the onshore Kimmeridge Clay Formation, UK

Abstract The occurrence and stratigraphical distribution of source rock potential in distal fine-grained facies is strongly related to the prevailing palaeo-oxygenation regime, especially during the deposition of the condensed section (CS). The CS will tend to correspond to organic facies B-AB, with good to excellent source-rock potential, only when conditions are dysoxic-anoxic, and organic facies D-CD, with poor source rock potential, when conditions are oxic. The applicability of the Creaney and Passey organic facies model is limited by its assumption that palaeo-oxygenation remains constant within the basinal facies. The CS commonly shows decimetre (Milankovitch)-scale redox cyclicity characterized by total organic carbon (TOC) and organic facies variations whose amplitude increases as sediment accumulation rates decrease. The greater frequency of dysoxic-anoxic conditions in the CS may be related to changes in accommodation space via the relationship between bottom water volume and the rate of deoxygenation, as observed in modern settings. The onshore Kimmeridge Clay diverges from the classic Exxon basin model as it was deposited in an intra-shelf setting where focusing and ponding of clayey sediment resulted in the basinal sections being both thicker and more complete. However, the best source rock intervals still coincide with the maximum flooding surfaces. The long-term Late Jurassic (shallow to deep to shallow) sea level curve appears to influence the mean (oxic to dysoxic-anoxic to oxic) palaeo-oxygenation regime in the basin and the background trend in sediment accumulation rate; it is expressed in a symmetrical increase in TOC to 4–6 wt% from background values of about 1 wt%. The superimposed decimetre- to metre-scale redox cycles appear to be controlled by Milankovitch climatic controls on water mass stratification. The relative spacing of these cyclic organic-rich interbeds decreases during relatively condensed (maximum flooding surface) intervals associated with the short-term sea-level curve, and the interval TOC values also increase and broaden. Intervals deposited during or shortly after lowstands are less organic-rich and have fewer and more widely spaced organic-rich beds. The individual organic-rich beds also appear to be condensed relative to adjacent mudstones; palynofacies and TOC versus hydrogen index data suggest the origin of these beds is due more to cyclically decreased dilution and redox conditions rather than enhanced palaeoproductivity.

Syn-sedimentary and burial related deformation in the Middle Jurassic non-marine formations of the Yorkshire Basin

Summary The non-marine formations of the middle Jurassic Ravenscar Group consist of channel sandstone bodies set in interbedded mudstones, silts and thin sheet sandstones. These rocks contain syn-sedimentary and burial related deformation structures. Frequent discharge fluctuations are deduced to have enhanced inherent river bank instability and with occasional tectonic movements produced a wide range of bank collapse structures. These had a low preservation potential and are observed at various stages of erosion. Several faults associated with channel sandstones can be related neither to tectonic activity nor to bank collapse. They may be explained as compensation structures formed during differential compaction of the sandstones and adjacent mudstones. Differential compaction structures form on a smaller scale around plant material, early diagenetic nodules and sandstone dykes. Continued sedimentation on the alluvial plain, together with differential compaction, produces a positive topography over channel sandstones. This effect was reduced by variations in deposition rate and facies. Laterally continuous beds deposited on this topography form gentle folds that are exaggerated by differential compaction during burial. Although most of the deformation seen in the Ravenscar Group is related to alluvial processes or sediment burial, some is connected to syn-sedimentary tectonic activity.

Deposition, Porosity Occurrence, and Reservoir Properties of San Andres Formation at Suniland Field, Lynn County, Texas: ABSTRACT

Suniland field is located in the west Texas Permian basin. Production is primarily from peritidal shelf dolomites of the Permian (Guadalupian) San Andres Formation. San Andres deposition was highly cyclical, with at least two upward-shoaling megacycles comprising the lower 600 ft (183 m) of the formation; many smaller cycles occur within the megacycles. The field consists of an elongate, low-relief, east-west-trending anticline formed from draping over a pre-San Andres structural high. Hydrocarbon trapping is controlled primarily by structural closure and discontinuity of San Andres reservoir facies. Anhydrite cement precipitation also may cause an updip (northerly) permeability loss. Reservoirs occur in thin, permeable oolitic grainstone intervals possessing primary intergranular porosity in combination with vugular and moldic pore systems. These grainstones interfinger with porous but generally impermeable oolitic packstones. Adjacent wackestones and mudstones are generally nonporous and impermeable. Porosity occlusion is primarily from precipitation of late dolomite cements. Anhydrite cements do not occlude porosity to a high degree. Oil production from the San Andres Formation at Suniland field is from nine separate reservoirs comprising two major pay categories, designated Sand Andres and lower San Andres. Pay depths range from 3,755 to 4,211 ft (1,144 to 1,283 m). Cumulative oil production to Januarymore » 1986 is 7.35 million bbl from 69 wells. Permian (Leonardian) Glorieta production accounts for about 16% of total production. Reservoirs produce from solution gas expansion at low gas-to-oil ratios and high water cuts. Effective porosity in pay zones averages 14%; permeability averages 17 md.« less

Relations of Lower Cretaceous and Upper Jurassic Rocks, Four Corners Area, Colorado

In many parts of the Colorado Plateau continuous conglomerate and sandstone lenses within the Burro Canyon formation (Early Cretaceous age) present a contrast to the dominantly mudstone upper part of the Morrison formation (Late Jurassic age). In the Four Corners area of southwestern Colorado, however, the lithologic character of the Burro Canyon is extremely variable, and in places the formation consists entirely of mudstone. The mudstone of the Burro Canyon formation and mudstone of the Brushy Basin member of the Morrison formation characteristically weather differently, the mudstone of the Burro Canyon to hackly fragments and mudstone of the Brushy Basin member to a hard frothy crust. This difference is believed due to original differences in composition rather than diagenetic processes, and it was found to persist throughout southwestern Colorado. The compensatory thickening of the Burro Canyon formation in relation to the Morrison formation, lateral change within short distances from mudstone of the Burro Canyon to mudstone of the Brushy Basin member, lack of evidence of a persistent unconformity between the Morrison and Burro Canyon, and the partial interbedding and intertonguing of the lowest conglomerate and sandstone of the Burro Canyon with mudstone of the Brushy Basin indicate that the Burro Canyon formation and Brushy Basin member of the Morrison formation are conformable and intertongue. The lack of fossil evidence prohibits precise placement of the Jurassic-Cretaceous time boundary. The lowest conglomerate in the Burro Canyon formation is part of a system of channel-filling conglomerate and conglomeratic sandstone lenses. The name Karla Kay conglomerate member is proposed for this system of lenses. A new sedimentary cycle accompanied by reduction in volcanic ash deposition is suggested by the Karla Kay conglomerate and adjacent mudstones of the Burro Canyon formation. The basal conglomerate of the Burro Canyon and Stokes' Buckhorn conglomerate member of the Cedar Mountain formation of central Utah may be lithogenic equivalents. The general decrease in the number of conglomerate and sandstone lenses southward in the Four Corners area of Colorado suggests that this area may be near the southern edge of deposition of the coarse clastic material of the Burro Canyon.