Reservoir characterization of Scollard-age fluvial sandstones,Alberta foredeep

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

The role of diagenesis and depositional facies on pore system evolution in a Triassic outcrop analogue (SE Spain)

This study aims at unravelling the diagenetic history and its effect on the pore system evolution of the Triassic redbeds exposed in SE Spain (TIBEM¹), an outcrop analogue of the TAGI (Trias Argilo-Gréseux Inférieur) reservoir (Berkine-Ghadames Basin, Algeria). Similar climatic, base level and tectonic conditions of aforementioned alluvial formations developed analogue fluvial facies stacking patterns. Furthermore, interplay of similar detrital composition and depositional facies in both formations resulted in analogue early diagenetic features. Petrographic observations indicate lithic subarkosic (floodplain facies) and subarkosic (braidplain facies) compositions which are considered suitable frameworks for potential reservoir rocks. Primary porosity is mainly reduced during early diagenesis through moderate mechanical compaction and formation of K-feldspar overgrowth, gypsum, dolomite and phyllosilicate cements. Early mesodiagenesis is testified by low chemical compaction and quartz cementation. Telodiagenetic calcite filling fractures and K-feldspar dissolution determined the final configuration of analysed sandstones. Mercury injection-capillary pressure technique reveals overbank deposits in the floodplain as the least suitable potential reservoirs because of their lowest open porosity (OP < 16%), permeability (k < 5 mD) and small dimensions. On the other hand, braidplain deposits show the highest values of such properties (OP up to 31.6% and k > 95 mD) and greater thickness and lateral continuity, so being considered the best potential reservoir. The accurate estimation of TIBEM microscale attributes can provide important input for appraisal and enhanced oil recovery performance in TAGI and in others reservoirs consisting on similar fluvial sandy facies.     

Diagenetic alterations and reservoir heterogeneity within the depositional facies: A case study from distributary-channel belt sandstone of Upper Triassic Yanchang Formation reservoirs (Ordos Basin,China)

Diagenesis is of decisive significance for the reservoir heterogeneity of most clastic reservoirs. Linking the distribution of diagenetic processes to the depositional facies and sequence stratigraphy has in recent years been discipline for predicting the distribution of diagenetic alterations and reservoir heterogeneity of clastic reservoirs. This study constructs a model of distribution of diagenetic alterations and reservoir heterogeneity within the depositional facies by linking diagenesis to lithofacies, sandstone architecture and porewater chemistry during burial. This would help to promote better understanding of the distribution of reservoir quality evolution and the intense heterogeneity of reservoirs. Based on an analogue of deltaic distributary channel belt sandstone in Upper Triassic Yanchang Formation, 83 sandstone plug samples were taken from 13 wells located along this channel belt. An integration of scanning electron microscopy, thin sections, electron microprobe analyses, rate-controlled porosimetry (RCP), gas-flow measurements of porosity and permeability, and nuclear magnetic resonance (NMR) experiments, together with published data, were analysed for the distribution, mineralogical and geochemical characteristics of detrital and diagenetic components and the distribution of reservoir quality within the distributary channel belt.Distribution of diagenetic alterations and reservoir heterogeneity within the distributary channel belt sandstones include (i) formation of high quality chlorite rims in the middle part of thick sandstones with coarser grain sizes and a lower content of ductile components resulted from the greater compaction resistance of these sandstones (providing larger pore spaces for chlorite growth), leading to formation of the intergranular pore – wide sheet-like throat and intergranular pore - intragranular pore – wide sheet-like throat (Φ>15%, k>1mD) in the middle part of thick sandstones; (ii) formation of thinner chlorite rims in the middle part of thinner sandstones is associated with the intergranular pore - intragranular pore – narrow sheet-like throat (9%<Φ<14%, 0.2mD<k<0.8mD); (iii) strong cementation by kaolinite in the more proximal sandstones of distributary channel owing to the strong feldspar dissolution by meteoric water, resulting in the intragranular pore - group of interstitial cement pores – narrow sheet-like throat/extremely narrow sheet-like throat (8%<Φ<11%, 0.1mD<k<0.3mD) due to the pore-filling kaolinite occluding porosity; (iv) formation of dense ferrocalcite zones (δ¹⁸O_VPDB = −23.4‰ to −16.6‰; δ¹³ C_VPDB = −4.0‰ to −2.3‰) favoured in the top and bottom of the channel sandstone which near the sandstone-mudstone bouding-surface, destroying pore space (Φ<8%, k<0.1mD); (v) strong compaction in sandstone of distributary channel edge laterally as a result of fine grain size and high content of ductile components in those sandstones, forming the group of interstitial cement pores – extremely narrow sheet-like throat with porosity values less than 8%.     

Features and sealing mechanism of shallow biogenic gas in incised valley fills (the Qiantang River,eastern China): A case study

Late Quaternary shallow biogenic gas reservoirs have been discovered and exploited in the Qiantang River (QR) estuary area, eastern China. The fall of global sea level during the Last Glacial Maximum resulted in the formation of the QR incised valley. From bottom to top, the incised valley successions can be grouped into four sedimentary facies: river channel facies, floodplain–estuarine facies, estuarine-shallow marine facies, and estuarine sand bar facies.All commercial biogenic gas pools occur in floodplain–estuarine sand bodies of the QR incised valley and its branches. The deeply incised valleys provided favorable conditions for the generation and accumulation of shallow biogenic gas.The clay beds that serve as the direct cap beds of the gas pools are mostly restricted within the QR incised valley, with burial depths ranging from 30 to 80 m, remnant thicknesses of 10–30 m, and porosities of 42.2–62.6%. In contrast, the mud beds cover the whole incised valley and occur as indirect cap beds, with burial depths varying from 5 to 35 m, thicknesses of 10–20 m, and porosities of 50.6–53.9%. The pore-water pressures of clay and mud beds are higher than that of sand bodies, and the difference can be as much as 0.48 MPa. The pore-water pressures of clay or mud beds can exceed the total pore-water pressure and gas pressure of underlying sand reservoirs. Shallow biogenic gas can be completely sealed by the clay and mud beds, which have higher pore-water pressure. The direct cap beds have better sealing ability than the indirect cap beds.Generally, the pore-water pressure dissipation time of clay and mud beds is conspicuously longer than that of sand beds. This indicates that the clay and mud beds have worse permeability and better sealing ability than the sand beds. However, once the gas enters the sand lenses, the pore-water pressure cannot release efficiently.     

Controls on reservoir heterogeneity of tight sand oil reservoirs in Upper Triassic Yanchang Formation in Longdong Area,southwest Ordos Basin,China: Implications for reservoir quality prediction and oil accumulation

Compared to conventional reservoirs, pore structure and diagenetic alterations of unconventional tight sand oil reservoirs are highly heterogeneous. The Upper Triassic Yanchang Formation is a major tight-oil-bearing formation in the Ordos Basin, providing an opportunity to study the factors that control reservoir heterogeneity and the heterogeneity of oil accumulation in tight oil sandstones.The Chang 8 tight oil sandstone in the study area is comprised of fine-to medium-grained, moderately to well-sorted lithic arkose and feldspathic litharenite. The reservoir quality is extremely heterogeneous due to large heterogeneities in the depositional facies, pore structures and diagenetic alterations. Small throat size is believed to be responsible for the ultra-low permeability in tight oil reservoirs. Most reservoirs with good reservoir quality, larger pore-throat size, lower pore-throat radius ratio and well pore connectivity were deposited in high-energy environments, such as distributary channels and mouth bars. For a given depositional facies, reservoir quality varies with the bedding structures. Massive- or parallel-bedded sandstones are more favorable for the development of porosity and permeability sweet zones for oil charging and accumulation than cross-bedded sandstones.Authigenic chlorite rim cementation and dissolution of unstable detrital grains are two major diagenetic processes that preserve porosity and permeability sweet zones in oil-bearing intervals. Nevertheless, chlorite rims cannot effectively preserve porosity-permeability when the chlorite content is greater than a threshold value of 7%, and compaction played a minor role in porosity destruction in the situation. Intensive cementation of pore-lining chlorites significantly reduces reservoir permeability by obstructing the pore-throats and reducing their connectivity. Stratigraphically, sandstones within 1 m from adjacent sandstone-mudstone contacts are usually tightly cemented (carbonate cement > 10%) with low porosity and permeability (lower than 10% and 0.1 mD, respectively). The carbonate cement most likely originates from external sources, probably derived from the surrounding mudstone. Most late carbonate cements filled the previously dissolved intra-feldspar pores and the residual intergranular pores, and finally formed the tight reservoirs.The petrophysical properties significantly control the fluid flow capability and the oil charging/accumulation capability of the Chang 8 tight sandstones. Oil layers usually have oil saturation greater than 40%. A pore-throat radius of less than 0.4 μm is not effective for producible oil to flow, and the cut off of porosity and permeability for the net pay are 7% and 0.1 mD, respectively.     

Diagenetic and sedimentary controls on porosity in Lower Carboniferous fine-grained lithologies,Krechba field,Algeria: A petrological study of a caprock to a carbon capture site

Fine-grained siliciclastic lithologies commonly act as sealing caprocks to both petroleum fields and host reservoirs for carbon capture (CO₂ sequestration) projects. Fine-grained lithologies are thus of great importance in controlling fluid flow and storage in the subsurface. However, fine-grained rocks are rarely characterised in terms of primary sedimentary characteristics, diagenesis and how these relate to their flow properties (i.e. sealing or caprock quality). Seventeen samples from Lower Carboniferous estuarine caprock to a gas field (also to be used as a carbon capture site), have been analysed using a range of petrological and petrophysical techniques. The rock unit that represents the caprock to this gas field was found to be predominantly silt grade with porosity values as low as 1.8%. In these rocks, caprock quality (porosity) is controlled by intrinsic and extrinsic factors linked to primary mineralogy and diagenetic processes. Depositional mineralogy was dominated by quartz, detrital mica, detrital clay (likely Fe-rich 7Å clay and illite–smectite) with minor feldspar and oxide phases. Diagenetic processes included compaction, minor feldspar dissolution and kaolinite growth and the more important processes of chlorite, siderite and quartz cementation, as well as the likely transformation of smectite into illite. Caprock quality is controlled by the primary quantity of illite-muscovite in the sediment and also by the localised extent of chlorite and quartz cementation. Deposition in an estuarine environment led to highly heterogeneous distribution of primary and diagenetic minerals, and thus caprock quality, between and within the samples.     

An interdisciplinary approach to reservoir characterisation; an example from the early to middle Eocene Kaimiro Formation,Taranaki Basin,New Zealand

The Kaimiro Formation is an early to middle Eocene, NE-SW trending reservoir fairway in Taranaki Basin, and comprises a range of coastal plain through to shallow marine facies. A time of regional transgression is observed across the Paleocene–Eocene transition, which is linked to a general global warming trend and to regional thermal relaxation-related subsidence in New Zealand. The earliest Eocene transgressive deposits pass upwards into a series of cyclically stacked packages, interpreted as 3rd and 4th order sequences. Maximum regression occurred within the early Eocene and was followed by punctuated retrogradational stacking patterns associated with shoreline retreat and subsequent regional transgression in the middle Eocene.The Kaimiro Formation is considered a good reservoir target along most of the reservoir fairway, which can largely be attributed to a consistently quartz-rich, lithic-poor composition and reasonably coarse sand grain size. Correlations demonstrate that within the early Eocene the main reservoir facies are channel-fill sandstones overlying candidate sequence boundaries in paleoenvironmentally landward (proximal) settings, and upper shoreface/shoreline sandstones in relatively basinward (distal) settings. Middle Eocene reservoir facies are not represented in distal wells due to overall transgression at this time, yet they form a significant target in more proximal well locations, particularly on the Taranaki Peninsula.Depositional facies is one of the principal controls on sandstone reservoir quality. However, while reservoir facies have been proven along the length of the reservoir fairway, it is evident that diagenesis has significantly impacted sandstone quality. Relatively poor reservoir properties are predicted for deeply buried parts of the basin (maximum burial >4.5 km) due to severe compaction and relatively abundant authigenic quartz and illite. In contrast, good reservoir properties are locally represented in reservoir facies where present-day burial depths are <4 km due to less severe compaction, cementation and illitisation. Within these beds (<4 km) the presence of locally occurring authigenic grain-coating chlorite (shallow marine facies) and/or well-developed secondary porosity are both favourable to reservoir quality, while pervasive kaolinite and/or carbonate are both detrimental to reservoir quality.These results illustrate how an interdisciplinary approach to regional reservoir characterisation are used to help reduce risk during prospect evaluation. Assessment of both reservoir distribution and quality is necessary and can be undertaken through integrated studies of facies, sequence stratigraphy, burial modelling and petrography.     

The permeability of faults within siliciclastic petroleum reservoirs of the North Sea and Norwegian Continental Shelf

Faulting in Middle Jurassic reservoirs occurred at shallow depth during regional extension. Clean sandstones (<15% clay) deformed without significant grain fracturing and permeability reduction. Faults in impure sandstones (15–40% clay) experienced significant syn-deformation compaction and permeability reduction. Enhanced compaction during deeper burial reduced their permeabilities further from an average of 0.05 mD at <2.5 km to 0.001 mD at >4 km. Clay-rich sediments (>40% clay) deformed to produce clay smears with very low permeabilities (<0.001 mD). Faulting in the Rotliegendes occurred at greater depth during both basin extension and inversion. Extensional faulting produced cataclasites with permeability reductions of <10–>10⁶; their permeabilities range from 0.2 to 0.0001 mD and are inversely related to their maximum burial depth. Faults formed or reactivated during inversion experienced permeability increase. These results can be extrapolated to other hydrocarbon reservoirs if differences in stress and temperature history are taken into account.The permeability of most (>80%) faults is not sufficiently low, compared to their wallrock, to retard single-phase fluid flow on a km-scale. Nevertheless, most faults could retard the flow of a non-wetting phase if present at low saturations. It may be necessary to incorporate the two-phase fluid flow properties of fault rocks into reservoir simulators using upscaling or pseudoisation techniques. Fault property data should be calibrated against production data before it can be used confidently.     

Controls on reservoir quality of Lower Cretaceous tight sandstones in the Laiyang Sag,Jiaolai Basin,Eastern China: Integrated sedimentologic,diagenetic and microfracturing data

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.     

Quartz cementation in Late Cretaceous mudstones,northern North Sea: Changes in rock properties due to dissolution of smectite and precipitation of micro-quartz crystals

Late Cretaceous mudstones from two wells located in the northern North Sea and the Norwegian Sea have been examined with respect to quartz cement. Two different types of quartz cement (Type 1 and Type 2) have been identified using SEM/EDS/CL-analysis of drill-bit cuttings at depths 2370–2670 m (80–85 °C). Type 1 appears as relatively large aggregates (30–100 μm) of depth/temperature related crypto- or microcrystalline to macrocrystalline irregular quartz cement formed by local re-crystallization of biogenic silica. The CL-responses of Type 1 quartz cement give a clear indication of an authigenic origin. Type 2 quartz cement represents relatively high amounts of extremely fine-grained micro-sized (1–3 μm) crystals embedded as discrete, short chains or small clusters/nests within the illitized clay matrix. The CL-responses of micro-quartz crystals indicate an authigenic origin. The micro-quartz is most probably sourced from silica released during the smectite to illite dissolution–precipitation reaction. The petrographic evidence indicates that most of the silica released by the smectite to illite reaction has not been exported out of the mudstones. The silica released produce a subtle inter-connected micro-quartz network interlocked with aggregates of micro-quartz and authigenic clay crystals. This micro-quartz cementation process causes a significant and sharp change in the mudstone stiffness at the onset of the chemical compaction regime. This is indicated by an abrupt increase in well log velocity (Vp) and change in seismic facies close to 2500 m (80/85 °C).     

Morphometry of micrite particles in cretaceous microporous limestones of the Middle East: Influence on reservoir properties

Microporosity may account for a significant part of the total porosity of Cretaceous limestone reservoirs of the Middle East. In these microporous facies porosity is moderate to excellent (up to 35%) while permeability is poor to moderate (up to 190 mD). Micritic limestones also may form dense layers with very low porosity and permeability values.Micritic samples were collected from three fields of the Habshan and Mishrif Formations, to examine the spatial relationship with their porosity, permeability and pore throat radius distributions. Two key parameters of the micritic particles are studied using scanning electron microscopy: their morphology (shape and inter-crystal contacts), and their crystallometry.Results reveal that micrite matrixes can be subdivided into three petrophysical classes. Class C (strictly microporous limestones with coarse punctic-to-partially coalescent micrites) is made up of coarse (>2 μm) polyhedral to rounded micritic crystals, it has good to excellent porosity (8-28%), poor to moderate permeability (0.2-190 mD) and a mean pore threshold radius of more than 0.5 μm. The class C is usually observed in rudist shoal facies where relatively high hydrodynamic energy disfavoured deposition of the finer micritic crystals. It also developed within meteoric leaching intervals below exposure surfaces. Class F (strictly microporous limestones with fine punctic-to-partially coalescent micrites) is composed of fine (<2 μm) polyhedral to rounded micrites with poor to excellent porosity (3-35%), but permeability values of less than 10 mD and a mean pore threshold radius of less than 0.5 μm. It is mostly observed in sediments deposited in a low energy muddy inner platform setting. Class D (strictly microporous mud-dominated facies with compact anhedral to fused dense micrites) comprises subhedral to anhedral crystals with sutured contacts forming a dense matrix. It has very low porosity and permeability. Class D is only found in low energy muddy inner platform facies and forms inter-reservoir or caps rock layers in close association with stylolites and clay contents that usually exceed 10%.     

Reservoir quality and rock properties modeling – Triassic and Jurassic sandstones,greater Shearwater area,UK Central North Sea

The complex burial and diagenetic histories of the Jurassic Fulmar and Triassic Skagerrak sandstones in the UK Central North Sea present significant challenges with regard to reservoir quality and rock property prediction. Commercial reservoir quality is retained despite deep burial and associated high temperatures and pressures. Shallow marine Fulmar sands are normally compacted (mean IGV = 26 ± 3%) yet have porosities of 21–33%. Porosity was preserved through inhibition of quartz cementation by clay and microquartz coatings, and enhanced by dissolution of framework grains (∼5%). Skagerrak fluvial sands are more compacted (mean IGV = 23 ± 2%), exhibit minor feldspar dissolution (<1%), and have porosities of 16–27%. Quartz cement averages only 2 ± 1.5% due to robust chlorite coats that cover 80% (±13%) of quartz surfaces.We modeled reservoir quality evolution using the forward diagenetic model Touchstone, which simulates porosity loss due to compaction and quartz cementation. Quantitative petrographic analyses and burial history data were used to calibrate Touchstone model parameters. The results were applied to deeper prospects for pre-drill prediction of porosity and permeability. In parallel, petrophysical data were used to characterize the elastic properties of the sandstones to provide a basis for quantitative seismic forward modeling. Experimental data and core-calibrated petrophysical results, reflecting variable in situ fluids and saturations, were used to build an elastic properties model. The model is robust and was used to generate fluid-filled sandstone properties, incorporating Touchstone results, for prospect-specific seismic attribute modeling. Well results from exploration wells are in good agreement with pre-drill Touchstone and elastic properties model predictions.     

Importance of vertical effective stress for reservoir quality in the Skagerrak Formation,Central Graben,North Sea

The complex fluvial sandstones of the Triassic Skagerrak Formation are the host reservoir for a number of high-pressure, high-temperature (HPHT) fields in the Central Graben, North Sea. All the reservoir sandstones in this study comprise of fine-grained to medium-grained sub-arkosic to arkosic sandstones that have experienced broadly similar burial and diagenetic histories to their present-day maximum burial depths. Despite similar diagenetic histories, the fluvial reservoirs show major variations in reservoir quality and preserved porosity. Reservoir quality varies from excellent with anomalously high porosities of up to 35% at burial depth of >3500 m below seafloor to non-economic with porosities <10% at burial depth of 4300 m below seafloor.This study has combined detailed petrographic analyses, core analysis and pressure history modelling to assess the impact of differing vertical effective stresses (VES) and high pore fluid pressures (up to 80 MPa) on reservoir quality. It has been recognised that fluvial channel sandstones of the Skagerrak Formation in the UK sector have experienced significantly less mechanical compaction than their equivalents in the Norwegian sector. This difference in mechanical compaction has had a significant impact upon reservoir quality, even though the presence of chlorite grain coatings inhibited macroquartz cement overgrowths across all Skagerrak Formation reservoirs. The onset of overpressure started once the overlying Chalk seal was buried deeply enough to form a permeability barrier to fluid escape. It is the cumulative effect of varying amounts of overpressure and its effect on the VES history that is key to determining the reservoir quality of these channelised sandstone units. The results are consistent with a model where vertical effective stress affects both the compaction state and subsequent quartz cementation of the reservoirs.     

Facies and architecture of an estuarine tidal bar (the Trompeloup bar, Gironde Estuary, SW France)

This study describes the sedimentary facies and internal architecture of a modern estuarine tidal bar present in the bay-head delta of a wave- and tide-dominated estuary, the Gironde Estuary, in southwest France. Based on 51 cores (2 to 5 m long), this work demonstrates that such bars are composite sedimentary bodies made up of individual sigmoidal sand units isolated from one another by thick muddy layers. The bar appeared in the study area around 1874. Since then, its evolution has been characterized by phases of rapid downstream bar migration alternating with periods of bar abandonment. During the periods of active bar progradation, which commonly last between 10 and 20 years, the bar progrades up to 7 km seaward and forms a narrow (200–800 m wide) sand ridge up to 6 m thick. During abandonment phases which also last around 10–20 years, the bar is starved of sand and a mud layer (1 to 3 m thick) is deposited. The vertical succession formed by the seaward progradation of the tidal bar records these alternating phases of growth and abandonment. A typical vertical succession in the bar system is 8 m thick and comprises several superimposed, upward-coarsening units of cross-stratified sand, deposited during phases of seaward progradation, separated by a thick layer of thinner-bedded mud and sand laminae deposited during phases of bar abandonment. When a tidal bar builds up to the supratidal zone, marshes accumulate and the bar becomes a permanent island in the estuary. The large-scale architecture of the bar is thus made of an alternation of potential sandy reservoir units and muddy internal seals. The reservoir units are characterized by a sigmoidal shape. The muddy layer, which is deposited between the two sigmoidal units, is a thick, continuous potential internal seal. This complex internal architecture is due to the fact that there is a considerable amount of mud present in the bay-head delta of the Gironde Estuary. It is thought to be representative of the architecture of tidal bars in the inner part of wave- and tide-dominated estuaries.     

Lithologic characteristics and diagenesis of the Devonian Jauf sandstone at Ghawar Field, Eastern Saudi Arabia

The Lower Devonian Jauf Formation in Saudi Arabia is an important hydrocarbon reservoir. However, in spite of its importance as a reservoir, published studies on the Jauf Formation more specifically on the reservoir quality (including diagenesis), are very few. This study, which is based on core samples from two wells in the Ghawar Field, northeastern Saudi Arabia, reports the lithologic and diagenetic characteristics of this reservoir. The Jauf reservoir is a fine to medium-grained, moderate to well-sorted quartz arenite. The diagenetic processes recognized include compaction, cementation (calcite, clay minerals, quartz overgrowths, and a minor amount of pyrite), and dissolution of the calcite cements and of feldspar grains. The widespread occurrences of early calcite cement suggest that the Jauf reservoir lost a significant amount of primary porosity at a very early stage of its diagenetic history. Early calcite cement, however, prevented the later compaction of the sandstone, thus preserving an unfilled part of the primary porosity. Based on the framework grain–cement relationships, precipitation of the early calcite cement was either accompanied or followed by the development of part of the pore-lining and pore-bridging clay cement. Secondary porosity development occurred due to partial to complete dissolution of early calcite cements and feldspar. Late calcite cement occurs as isolated patches, and has little impact on reservoir quality of the sandstones.In addition to calcite, several different clay minerals including illite and chlorite occur as pore-filling and pore-lining cements. While the pore-filling illite and chlorite resulted in a considerable loss of porosity, the pore-lining chlorite may have helped in retaining the porosity by preventing the precipitation of syntaxial quartz overgrowths. Illite, which largely occurs as hair-like rims around the grains and bridges on the pore throats, caused a substantial deterioration to permeability of the reservoir. Diagenetic history of the Jauf Formation as established here is expected to help better understanding and exploitation of this reservoir.     

Sedimentary facies and evolution in the Qiantang River incised valley,eastern China

This paper deals with the sedimentary facies and evolution of the Qiantang River (QR) estuary, and the characteristics and formation of the incised valley sequences and the related shallow biogenic gas reservoir, on the basis of analysis of over 500 cores.The result shows that, since the last glaciation, the Late Quaternary formation of the QR estuary area underwent three stages: (1) deep-cutting stage; (2) rapid-filling stage; and (3) burial stage. The fall of global sea level during the last glacial maximum enhanced the fluvial gradient and river cutting, resulting in the formation of the large-scale QR and Taihu incised valleys, with the interfluve being exposed to air on both flanks of the incised valley. Fluvial terraces at the elevations are present near the present QR estuarine mouth, corresponding to 60–70, 90–100 and 115–125 m burial depths. The valleys were filled rapidly with fluvial sediments during the post-glacial period; with the rise of sea level, the river mouth migrated to landward, and backwater and retrogressive aggradation was enhanced. The QR and Taihu incised valleys are associated with an early filling and transgressive channel-infilling sequence formation, and a late filling and transgressive floodplain-estuary formation. Subsequently, the QR valley was buried under estuarine-marine and estuarine sand bar sediments. From bottom to top, the incised valley successions can be grouped into four sedimentary facies: river channel, floodplain-estuary, estuary-shallow marine, and estuary sand bar.The thickness of the river channel-infilling deposits is controlled mainly by base level rising, backwater, retrogressive aggradation and neotectonism. Further, localized thickening took place where deeper scour pools were present in the incised valley or fluvial terraces were formed during the fall of elative sea level.During the deposition of the floodplain-estuary facies, the conditions of sea level rise, tidal regime, sediment supply and accommodation space were suitable for the development of a tidal ridge system; the sand lenses associated with this facies may represent a tidal ridge system in the incised valley. At the later stage when the estuarine sand bars were formed, the sedimentary conditions were no longer favourable, resulting in absence of sand ridge deposits. Biogenic gas is stored in the floodplain-estuary sand lenses of the incised valleys. The Changjiang River provides the major sediment supply for the QR estuary sand bar, and the QR carried sediments constitute only a small portion of the deposits.     

Permeability heterogeneity in bioturbated sediments and implications for waterflooding of tight-oil reservoirs,Cardium Formation,Pembina Field,Alberta, Canada

Bioturbated sediments recording distal expressions of paralic depositional environments are increasingly being exploited for hydrocarbons in the super-giant Pembina Field (Cardium Formation), Alberta, Canada. These strata were previously considered unproductive due to limited vertical and horizontal connectivity between permeable beds. In these “tight oil” plays (0.1–10 mD), pressure decay profile permeametry (micropermeability) data indicate that sand-filled burrows provide vertical permeable pathways between bioturbated and parallel-laminated sandstone beds in the central, northeast and northwest parts of the field. This relationship enables the economic exploitation of hydrocarbons via horizontal drilling and multi-stage hydraulic fracturing. As the exploitation of bioturbated strata progresses in the Pembina Field, additional primary targets are being sought out, and horizontal waterflooding is being considered in areas where horizontal wells exist. Proximal to historical produced conventional targets, reservoir analyses indicate that areas where the bioturbated facies average permeability lies between 0.35 mD and 0.85 mD and sandstone isopach thicknesses are between 0.25 m and 2.5 m should be targeted in east-central Pembina.Micropermeability values enable correlation of bulk permeability from plugs and full-diameter samples to the heterogeneous permeability distributions in intensely bioturbated strata. Bulk and micropermeability data are graphically compared, and permeability distributions are mapped across the field. Using isopach thickness of bioturbated facies, production data, and permeability data, “sweet spots” are identified for placement of effective waterfloods.Production information for recently drilled horizontal wells in the Pembina Field demonstrate that bioturbated muddy sandstones and sandy mudstones in paralic environments can be economically exploited when sand-filled burrows provide connectivity between sand beds. However, well performance within these poorly understood unconventional tight oil plays can better be predicted with an in-depth characterization of their facies and complex permeability heterogeneities. Based on our results, it is clear that micropermeability analysis can be effectively employed to differentiate between economic and sub-economic plays, identify areas with high effective permeability, and high-grade areas for enhanced oil recovery schemes.     

The diagenetic history of Oligocene-Miocene sandstones of the Austrian north Alpine foreland basin

Diagenesis is an essential tool to reconstruct the development of reservoir rocks. Diagenetic processes - precipitation and dissolution - have an influence on pore space. The present paper aims to study the diagenetic history of deep-marine sandstones of the Austrian Alpine Foreland Basin. To reach that goal, sediment petrology and diagenetic features of more than 110 sandstone samples from water- and gas-bearing sections from gas fields within the Oligocene-Miocene Puchkirchen Group and Hall Formation has been investigated. Special emphasis was put on samples in the vicinity of the gas-water contact (GWC). The sediment petrography of sandstones of Puchkirchen Group and Hall Formation is similar; hence their diagenesis proceeded the same way. In fact, primary mineralogy was controlled by paleo-geography with increasing transport distance and diverse detrital input.Sediment petrographically, investigated sandstones from the water-bearing horizon seemed quite comparable to the gas-bearing sediments. In general, they can be classified as feldspatic litharenites to litharenites and display porosities of up to 30% and permeabilities of up to 1300 mD. The carbon and oxygen isotopic composition of bulk carbonate cements from these sandstones range from−3.8 to +2.2 and from −7.5 to +0.2‰ [VPDB]. However, near the Gas-Water Contact (GWC) a horizon with low porosities (<3%) and permeabilities (<0.1 mD) is present. This zone is completely cemented with calcite, which has a blocky/homogenous morphology. A slight, but significant negative shift in δ18O isotopy (−2.5‰) is evident.During early diagenesis the first carbonate generations formed. First a fibrous calcite and afterwards a micritic calcite precipitated. Further siliciclastic minerals, such as quartz and feldspar (K-feldspar and minor plagioclase), exhibit corroded grains. Occasionally, clay minerals (illite; smectite, chlorite) formed as rims around detrital grains. Late diagenesis is indicated by the formation of a low permeable zone at the GWC.     

Experimental evaluation of reservoir quality in Mesozoic formations of the Perth Basin (Western Australia) by using a laboratory low field Nuclear Magnetic Resonance

Accurate porosity and permeability evaluation of rock formations is critical to estimate the quality and resource potential of a reservoir. In addition to directly measure the porosity and pore size distribution, low field Nuclear Magnetic Resonance (NMR) is able to measure the effective porosity and estimate the in-situ formation permeability, though its robustness is arguable and requires calibrations on cores with specific lithologies.The Mesozoic formations of the central Perth Basin (Western Australia) host hot sedimentary aquifers and recently became key targets for geothermal heat extraction. A collection of cores was retrieved from three wells intersecting these units. The characterisation of their flow properties complements the current evaluation of the Perth Basin by adding new data on effective porosity, pore size distribution, pore geometry and calibration of predictive models for the permeability according to a comprehensive facies classification scheme.This study highlights the consistency of the NMR approach when compared to conventional helium injection method. Most favourable lithologies for well production correspond to very coarse to fine sandstones of fluvial channel fill with porosities >15% and permeabilities >>1 mD. Similarly, these facies exhibit (i) the highest effective porosities, (ii) the highest pore space to pore throat ratio, and (iii) the lowest contribution of clay bound water. These aspects confirm the importance of clay occurrence in the assessment of the flow efficiency of a formation.The Yarragadee Formation presents the best reservoir quality regarding its porosity and permeability, even though high discrepancies occur locally owing to the great variability of lithofacies encountered. The scattered values observed for the Lesueur Sandstone are likely to be due to the basin architecture and fault system which generate different mechanical compaction and secondary cementation. Given an adequate facies analysis, the NMR method represents a powerful tool to estimate the flow efficiency of a reservoir.