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Summary The so-called “dense zones” (intervals of very low porosity) separating the thicker, high-porosity reservoir intervals of Lower Cretaceous limestone strata in the Abu Dhabi subsurface have been studied in cores from a giant onshore oilfield. Although holding no oil reserves, the dense zones are important elements of reservoir architecture and essential components of any sequence stratigraphic interpretation, yet little substantive work has been reported regarding their description and origin. The present study of the two dense zones enclosing the upper reservoir zone of the Kharaib Formation reveals that they have similar ranges of bulk chemical composition, with much higher aluminum, iron, potassium, thorium, and uranium than the intervening reservoir zone, but are very different from one another in depositional texture. The upper dense zone consists mainly of peloid-orbitolinid packstone, whereas the next-lower dense zone consists mainly of orbitolinid mudstone. Both dense zones display cycle-like gamma ray variations that correlate throughout the field, reflecting varying content of clay and pyrite. The high clay content of the dense zones accounts for their extreme early loss of porosity and is explained as the result of their stratigraphic position, associated with (either preceding or immediately following) third-order sea-level lowstands.

The upper zone of the Lower Cretaceous Kharaib Formation (151–177 ft [46–54 m] thick in the studied wells) is a major oil reservoir in several giant oil fields. Wide variations in porosity and permeability of this zone have been shown to result from both the inhibition of burial cementation by oil in the crest of each field and localized cementation adjacent to stylolites, combined with the more subtle influence of widely varying depositional mud content and grain size. The present study examines these relationships in closer detail, using core and petrographic observations from two wells on the oil-filled crest and two wells on the water-filled flanks of a giant domal oil field. Although porosities are higher overall in the crestal cores, each well shows wide variations within each of seven main groupings of the samples by depositional texture. This heterogeneity results mainly from the distribution of clay, which is concentrated along depositional laminations and causes widely varying porosity losses in all textures by promoting stylolite development and associated calcite cementation. Higher clay abundance (and lower porosity) within the upper and lower 12–17 ft (4–5 m) of the reservoir reflects increased influx of siliciclastic fines across the epeiric Barremian carbonate platform immediately following and preceding, respectively, third-order falls in global sea level. Most (95%) of porosity-permeability data from the studied wells lie within Lucia rock-fabric class 3, showing distinct but relatively subtle differences between texture groups, whereas a subordinate part of the data from the upper, relatively mud-poor third of the reservoir plot at higher permeabilities. Development of a predictive model for the petrophysical heterogeneity of this example requires a combination of the following: (1) a diagenetic model for porosity controls; (2) the use of a modestly higher porosity-permeability transform (upper class 3) in the upper part of the reservoir than in the lower reservoir (lower class 3); and (3) a recognition of the scattered and widely varying occurrences of exceptionally high permeabilities in the upper reservoir.

The upper reservoir zone of the Lower Cretaceous Kharaib Formation (46–54 m thick in the studied wells) is regarded as the upper portion of a third-order depositional sequence comprising higher-order cycles. Whereas the third-order sequence interpretation is clearly supported by the upward-shoaling trend of the reservoir zone, relationships defining the component cycles have not previously been documented and are the focus of the present study. Core descriptions from four wells in a single oilfield reveal little evidence of facies changes or trends of facies patterns indicative of high-frequency depositional cycles. Cycle boundaries could possibly be represented by the repetitive pattern of coarse beds (rudstone and floatstone) 0.1–2 m thick, commonly having sharp basal contacts and gradational upper contacts with enclosing packstone to wackestone. Because the coarse beds do not appear correlative between wells, however, we prefer the alternative interpretation that they reflect episodic storm events which locally redistributed detritus, sourced from a patchwork of low-relief lithosomes, across the flat surface of the epeiric Kharaib platform–lagoon. Although the existence of high-order eustatic fluctuations during upper Kharaib deposition is well established, low-amplitude variations in water depth may not have touched down on the sea floor to significantly affect sediment textures in contrast with the dominant storm signal.Reservoir sub-zones used for production operations, but previously suggested to be fourth-order parasequence sets, are defined by dips in porosity-log profiles, reflecting thin (approximately 1 m) intervals of increased stylolite frequency. These boundaries are thus diagenetic in character, but their correlation over tens to hundreds of kilometers indicates an underlying depositional control. We suggest that the link between sea level and diagenesis is depositional-clay content, which facilitates stylolitic dissolution. Profiles of bulk-rock alumina analyses in the studied cores show subtle indications of higher clay content at the sub-zone tops. Much greater clay peaks mark the third-order sequence boundaries, resulting in the “dense” (very low porosity) zones above and below the studied reservoir zone and the increased stylolite frequency in the upper and lower several meters of the zone. Possible factors promoting clay influx across a carbonate shelf during falls in sea level include increased stream gradients and more humid climate.

Abstract The vertical distribution of bedding-parallel stylolites in cores from the approximately 50-m-thick Thamama-B reservoir zone of the Lower Cretaceous Kharaib Formation is compared between two wells on the water-filled flanks and two wells on the crest of a giant oilfield where oil has previously been interpreted as having preserved higher porosity on the crest. Stylolite abundances indicate division of the reservoir zone into three intervals: The top 12 ft (3.7 m) of the zone contains abundant low-amplitude stylolites in both crest and flank locations. The main, central part of the zone has abundant high-amplitude stylolites in the flank wells but nearly no stylolites in the crest. The basal 17 ft (5.2 m) of the zone contains high-amplitude stylolites in all wells, but these are somewhat more abundant in the cores from the crest of the field. The contrast in stylolite abundance in the center interval is consistent with oil having inhibited chemical compaction on the crest of the field. Minor dissolution along wispy seams in the center interval of the crest is interpreted as representing an incipient stage of stylolite development. The similarity in stylolite abundance in the top interval between crest and flank wells is interpreted as reflecting stylolite formation pre-dating oil emplacement because of greater depositional concentration of clay in thin laminations resembling flaser bedding. Stylolite growth in the basal interval may also partly predate oil filling, but the evidence for timing is unclear because stylolites in the heavily bitumen-stained basal interval of the crestal wells have thick bitumen coatings that may be residues from dissolution of the surrounding limestone. Negative correlation between porosity and both amplitude and proximity of stylolites supports the model of porosity loss by calcite cementation derived from stylolites. The overall porosity difference between crest (22%) and flanks (12–16%) approximately matches the volume of cement that would have been supplied by the thickness of strata dissolved on the flanks. The match between porosity difference and thickness variation supports a diagenetic system closed to significant calcite import or export. Profiles of bulk-chemical analyses reveal how clay (proportional to aluminum) and dolomite (proportional to magnesium) vary both vertically in the formation and laterally between the crest and flank locations. Higher clay values, suggested to facilitate stylolite development, occur mainly in the top and basal parts of the zone, reflecting episodic deposition of siliciclastic fines. Higher dolomite contents throughout the wackestone-dominated lower two thirds of the reservoir zone (around 5–10 wt. %) than in the grain-supported upper one third (little or no dolomite) are suggested to reflect differences in early dolomitization by seawater attending slower sedimentation rates in the lower part of the zone. Like the variations in chemical compaction, dolomitization is thus a manifestation of the layer-cake geometry of this reservoir. Detailed core descriptions from each well and tables of bulk-rock chemical analyses and stylolite data are available as supplemental material.

To better understand reservoir quality in a major oil-producing limestone unit, the Thamama-B zone of the Lower Cretaceous (Barremian) Kharaib Formation, this study compiles and analyzes average values of porosity and permeability measured on 330 well cores in both onshore and offshore areas of the Abu Dhabi Emirate. Most average and individual values plot along a single porosity-permeability trend, which is unaffected by porosity-preserving early oil emplacement and only moderately influenced by texture and clay content. The main trend corresponds with the established field for mud-dominated, microporous limestones, but a subordinate proportion, termed “hi-K” plug samples, have significantly higher permeability-for-given-porosity. The hi-K samples are more abundant in the southwestern part of the study area and also show spatial clustering within individual oilfields. The present macro-scale view of Thamama-B reservoir quality is a new resource that can be useful for both exploration and production planning.

We present a large dataset of average porosity, depth, thickness and well locations for one of the Earth's major oil-bearing limestone reservoirs and discuss possible controlling factors. Petrologic data are not included in this study, but regional petrology data from earlier studies and detailed results from one representative oilfield provide a useful basis for interpretation of the present compilation. Porosity decreases with depth similar to porosity-depth trends from other limestone strata, but the main data cluster, representing the largest fields in the depth range 7000–9500 ft (2134–2896 m), follows a much steeper trend approximately parallel with the crest-flank trends of individual fields where crestal porosity has apparently been preserved by early arrival of oil. Maps of depth, porosity, thickness, and departure of porosity from the overall trend illustrate the geographic variation of these parameters. Solidity (thickness with porosity removed) is constant from crest to flanks in the largest fields, indicating that crest-flank porosity differentiation took place by closed-system compaction and cementation. The principal value created by this work is the framework established for focusing continuing studies that can further constrain the controlling processes and thus develop predictive tools for this particular reservoir and similar micropore-dominated limestones worldwide.

Summary The upper reservoir zone of the Lower Cretaceous Kharaib Formation (46–54 m thick in the studied wells) is regarded as the upper portion of a third-order depositional sequence comprising higher-order cycles. Whereas the third-order sequence interpretation is clearly supported by the upward-shoaling trend of the reservoir zone, relationships defining the component cycles have not previously been documented and are the focus of the present study. Core descriptions from four wells in a single oilfield reveal little evidence of facies changes or trends of facies patterns indicative of high-frequency depositional cycles. Cycle boundaries could possibly be represented by the repetitive pattern of coarse beds (rudstone and floatstone) 0.1–2 m thick, commonly having sharp basal contacts and gradational upper contacts with enclosing packstone to wackestone. Because the coarse beds do not appear correlative between wells, however, we prefer the alternative interpretation that they reflect episodic storm events which locally redistributed detritus sourced from a patchwork of low-relief lithosomes across the flat surface of the epeiric Kharaib platform-lagoon. Although the existence of high-order eustatic fluctuations during upper Kharaib deposition is well established, low-amplitude variations in water depth may not have touched down on the sea floor to significantly affect sediment textures in contrast with the dominant storm signal. Reservoir sub-zones used for production operations, but previously suggested to be fourth-order parasequence sets, are defined by dips in porosity-log profiles, reflecting thin (approximately 1 m) intervals of increased stylolite frequency. These boundaries are thus diagenetic in character, but their correlation over tens to hundreds of kilometers indicates an underlying depositional control. We suggest that the link between sea level and diagenesis is depositional clay content, which facilitates stylolitic dissolution. Profiles of bulk-rock alumina analyses in the studied cores show subtle indications of higher clay content at the sub-zone tops. Much greater clay peaks mark the third-order sequence boundaries, resulting in the “dense” (very low porosity) zones above and below the studied reservoir zone and the increased stylolite frequency within the upper and lower several meters of the zone. Possible factors promoting clay influx across a carbonate shelf during falls in sea level include increased stream gradients and more humid climate.

A study of limestone cores from the Upper Shu’aiba Member (upper Aptian) in an oilfield in northwestern Oman shows examples of a cementation phenomenon that appears to be widespread in microporous carbonate reservoirs and fundamental for understanding their porosity evolution during burial diagenesis. The studied reservoirs have total porosity of 4 to 36%, which consists mainly of “micropores,” defined here as pores not distinctly visible in a petrographic thin section (thus generally

The fact that reservoir sub-zones (previously suggested to be fourth-order parasequence sets) are defined by dips in the porosity log profiles, reflecting increased stylolite frequency, indicates that these boundaries are diagenetic in character. Nevertheless, the correlation of these features over tens to hundreds of kilometers indicates an underlying depositional control. We suggest that the link between sea level and diagenesis is depositional clay content, which facilitates stylolitic dissolution. Profiles of bulk-rock alumina analyses in the studied cores tend to confirm higher clay contents at the sub-zone tops. Possible factors promoting clay influx onto a carbonate shelf during falls in sea level include increased stream gradients and a more humid climate, causing greater rainfall and higher weathering rate.

Core samples from seven wells in Lower Cretaceous limestones of the Upper Shu’aiba Member were characterized by conventional core analyses, petrography, bulk chemistry and mercury-injection capillary pressure data to define reservoir rock types (RRT). In the main oilfield studied, lithofacies are arranged in three main belts corresponding to ramp crest, upper slope and lower slope, with bioclast content and size decreasing down depositional dip. Rock typing is based on the observation of distinct, but overlapping, porosity–permeability transforms for each lithofacies, although most samples plot in or below the class 3 field of Lucia, reflecting the presence of abundant lime-mud matrix. Because of the wide range of porosity in each of the main lithofacies, an arbitrary division at 20% porosity is used in combination with lithofacies to define RRT with both three-dimensional (3D) geological significance and distinct ranges of permeability and capillary pressure characteristics. The use of total porosity as a rock-typing criterion is based on the interpretation that porosity is controlled on the reservoir scale by the depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms a have low clay, and, thus, highest porosity. Because both lithofacies and porosity are linked to the sedimentological and stratigraphic organization of the Upper Shu’aiba clinoforms, the RRT can potentially be implemented in a reservoir model for assigning distinct ranges of petrophysical properties to the different architectural elements comprising each clinoform. Two additional grain-dominated RRT have also been defined in a single core that was available from a second oilfield.

Core and log data from Lower Cretaceous limestones of the Upper Shu’aiba Member were used to characterize the distribution of lithofacies, clay and porosity within two low-angle clinoforms that form the reservoirs for an oilfield of northwestern Oman. Data from 15 vertical wells, including four with core, and four horizontal well cores were projected into a dip-oriented cross-section derived from a static reservoir model as a basis for visualizing the above variations. Each clinoform consists of a basal “argillaceous zone” and a thicker “reservoir zone” of clean limestone, together reflecting fourth-order cycles of progradation along the margin of the Bab intra-shelf basin. Lithofacies vary in a proximal direction from mudstone and wackestone (mid-ramp) to mud-dominated packstone (slope) to mud-rich floatstone, rudstone and boundstone (ramp crest) and are arranged in a pattern of decreasing water depth and increasing energy both upwards and landward within each clinoform. In contrast, the reservoir zone of a younger clinoform from a nearby oilfield consists of well-sorted grainstone and grain-dominated packstone, illustrating the wide range of depositional conditions that occurred in the ramp-crest facies belt of different units.Except within the proximal extent of the younger clinoform, where values are transitional toward reservoir zone values, the argillaceous zones have total porosity mostly < 10% and baseline-normalized gamma-ray (GR) activity > 23 API units, reflecting clay contents of around 10–18%. In contrast, most parts of the reservoir zones have GR of 15–23 API units and porosity of 10–35%. Higher clay content is suggested to be linked with lower porosity through facilitation of both mechanical and chemical compaction, the latter providing a local supply of calcite cement. XRD analyses show that the clays are kaolin, illite/smectite and illite, similar to the clays in the overlying Nahr Umr shale. Most former macropores have been filled by blocky calcite cement in the main oilfield studied, but all lithofacies have similar wide ranges of total porosity of 8% to > 30%.The cores were also studied for evidence of diagenesis related to the contact with the overlying Nahr Umr Formation, but profiles of stable-isotope ratios, bulk-rock strontium, petrography and porosity-permeability data show no trends indicative of upward-increasing meteoric diagenesis below this sequence boundary. Meteoric leaching could nevertheless be pervasive throughout the Upper Shu’aiba reservoirs, at least partially accounting for extensive aragonite dissolution and low Sr and δ18O values. Two of the cores show trends of upwards-increasing bulk-rock uranium, manganese and iron, possibly indicative of sea-floor authigenesis. In addition, saddle dolomite near the tops of these cores may reflect late influx of magnesium derived from clay in the Nahr Umr Formation.

An outcropping stratigraphic section of the Asmari Formation near the city of Al Ain in the United Arab Emirates is examined using a measured section, thin sections, and both geochemical and petrophysical analyses. This formation is the only known strata of Oligocene age outcropping in southeast Arabia and should not be confused with strata of overlapping age and the same name in southwest Iran. The 230-m measured section is divided into four intervals of distinctive depositional facies, representing progradation of a reefal margin and its surrounding environments. Siliciclastic content and dolomitization tend to increase with distance from the coarse-grained platform margin. A key finding is how the strata have undergone extensive diagenesis, although buried to

The "dense zones" (intervals of very low porosity) separating Lower Cretaceous reservoir zones have been studied in cores from a giant onshore oilfield. The topics addressed in this paper include the nature of gamma ray (GR) activity in the dense zones, lithofacies, the nature of bedding and depositional cycles, lateral variation in thickness and porosity within the field studied, the timing of porosity loss, and the causes of the very low porosity of the dense zones.

Bed-parallel stylolites are a widespread diagenetic feature in Lower Cretaceous limestone reservoirs, Abu Dhabi, United Arab Emirates (UAE). Diagenetic calcite, dolomite, kaolin and small amounts of pyrite, fluorite, anhydrite and sphalerite occur along and in the vicinity of the stylolites. Petrographic observations, negative δ 18 O VPDB , fluid inclusion microthermometry, and enrichment in 87 Sr suggest that these cements have precipitated from hot basinal brines, which migrated along the stylolites and genetically related microfractures (tension gashes). Fluid migration was presumably related to lateral tectonic compression events related to the foreland basin formation. The low solubility of Al 3 + in formation waters suggests that kaolin precipitation was linked to derivation of organic acids during organic matter maturation, probably in siliciclastic source rocks. The mass released from stylolitization was presumably re-precipitated as macro- and microcrystalline calcite cement in the host limestones. The flanks of the oilfield (water zone) display more frequent presence and higher amplitude of stylolites, lower porosity and permeability, higher homogenization temperatures and more radiogenic composition of carbonates compared to the crest (oil zone). This indicates that oil emplacement retards diagenesis. This study demonstrates that stylolitization plays a crucial role in fluid flow and diagenesis of carbonate reservoirs during basin evolution.

Eight samples of brachiopod shell material have been analyzed for their strontium isotope composition in order to more accurately date Lower to Upper Permian siliceous biogenic strata of Spitsbergen (Kapp Starostin Formation) and the southern Barents Sea (Roye Formation). The results are interpreted as showing a mid-Artinskian age for the basal Voringen Member of the Kapp Starostin Formation and a range of late Artinskian to Roadian for the overlying part of this unit. The upper part of the Roye Formation yields ages in the range Roadian to Wuchiapingian. These results are consistent with available biostratigraphic data and confirm the potential of strontium isotope stratigraphy for developing a more accurate chronology of the widespread spiculite deposits that characterize the northern margin of Pangea in late-Early Permian to Late Permian time and which constitute a potential target for petroleum exploration.

Average porosity values for the producing zones of oil and gas fields worldwide are examined as a function of the present depth for sandstone and carbonate lithologies divided into 10 groupings by reservoir depositional age (Precambrian–Silurian to Pliocene–Pleistocene). The wide variations in average reservoir porosity within each depth range reflect the extreme ranges in porosity-controlling factors such as depositional facies, early

A publicly available data set has been examined for relationships between average values of porosity, permeability, depth, temperature, pressure, thickness, age, and play type for 11,833 sandstone reservoirs, mostly of Miocene age and younger, from the United States offshore Gulf of Mexico (GOM). Porosity shows wide scatter as a function of burial depth, but the median (P50) porosity trend decreases smoothly with depth. The GOM trend has much higher porosity for the given depth than the P50 trend of sandstone reservoirs worldwide, reflecting rapid sedimentation rates and young ages of GOM reservoirs, most of which have spent relatively little time at temperatures more than 80C, where quartz cementation becomes active. Multivariate regression analysis shows that porosity is best predicted by temperature (r2 = 0.40), with the fit improved slightly by adding age and then depth (r2 = 0.44). Arithmetic average permeability (represented by its logarithm) shows a correlation of maximum and P50 trends with porosity. GOM P50 permeability lies 0.2–0.4 log units below the P50 trend for sandstone reservoirs worldwide, probably reflecting very fine grain size of most GOM sands. Water saturation can be used to calculate the effective (petroleum-filled) porosity of each reservoir, which shows strong correlation with permeability. Grouping the reservoirs by chronozone reveals regular trends of decreasing average porosity and permeability with increasing age, reflecting increasing average depth and temperature with age. Porosity and permeability functions representing depositional sand quality show only subtle differences between different age groupings and play types. The results presented here can be useful for specifying realistic distributions of parameters for both exploration risk evaluation and reservoir modeling.

Stylolites are ubiquitous in petroleum reservoirs and are important as potential sources of ions for cementation and as heterogeneities affecting fluid flow. The factors controlling the initiation and morphology of stylolites have been discussed in many previous studies, but a significant problem for such interpretation is that the original rock before the stylolites formed is generally not available for study, having been highly altered by dissolution, especially along and immediately adjacent to the locations of key interest. The present study addresses this problem by comparing cores from the water-filled flanks of a giant oilfield, where stylolites are abundant, with cores from the oil-filled crest, where stylolite formation was inhibited by the earlier emplacement of oil.. Because the investigated reservoir zone shows a high degree of lateral stratigraphic continuity over large distances, crest and flank locations appear to be closely similar in depositional character. Comparison of these locations is thus used for a sort of geological time-travel; to be able to see the more chemically compacted and cemented flank sections as they were before the oil arrived and abundant, high-amplitude stylolites formed along the flanks. The results are interpreted to discuss the relative timing of different stylolites, the factors controlling stylolite formation, and the relationship between stylolites and the porosity of the enclosing limestones.

This study compares laboratory measurements of porosity and permeability between twenty-three whole-core samples and fifty-four 1-in. (25-mm) plugs drilled from the centers of the same samples. All samples are coarsely bioclastic carbonates from Miocene carbonate platforms of the Marion Plateau, offshore northeast Australia (1 limestone and 22 dolostones). Whole-core porosities tend to be slightly higher (average 1.4 porosity units) than plug porosities, probably reflecting a lower surface/volume ratio for the larger samples. Permeability differences between whole cores and plugs vary greatly from sample to sample, but whole-core permeability tends to be higher in cases where larger differences are observed. This tendency may reflect flow through optimal-flow networks that occupy a small proportion of the total rock volume and are therefore not included within most plugs. Previous studies suggest that increasing permeability with sample scale may be a general characteristic of heterogeneous porous media. The present results provide a quantitative basis for evaluating the necessity and advantages of using whole cores as opposed to plugs for petrophysical characterization of carbonate reservoirs.

The Asmari Formation has been studied in the subsurface at the Bibi Hakimeh, Marun and Ahwaz oilfields and in an outcrop section from the Khaviz anticline. It consists of approximately 400 m of cyclic platform limestones and dolostones with subordinate intervals of sandstone and shale. The method of Sr-isotope stratigraphy is well suited for dating these strata because of the rapid rate of change of marine Sr-87/Sr-86 during Asmari deposition (roughly 32-18 Ma) and the common presence of well-preserved macrofossils.Profiles of age against depth in the four areas show a decrease from higher stratigraphic accumulation rates in the lower Asmari to lower rates in the middle to upper part of the formation. There is also a trend towards less open-marine depositional conditions and increasing early dolomitization and anhydrite abundance above the lower part of the formation. These changes reflect the dynamics of platform progradation across the areas studied, from early deposition along relatively high accommodation margin to slope settings to later conditions of lower accommodation on the shelf top.Ages of sequence boundaries are estimated from the age-depth profiles at each locality, providing a framework for stratigraphic correlation. Asmari deposition began in early Rupelian time (34-33 Ma) in the Bibi Hakimeh area, when the studied areas to the NW were accumulating basinal marl facies. Progradation of the platform across the Marun and Ahwaz areas took place in mid-Chattian time (27-26 Ma) and somewhat later (26-25 Ma) in the more basinward Khaviz area. Depositional sequences have durations of 1-3 Ma, whereas component cycles represent average time intervals of 100-300 Ky.Sr analyses of most dolomite, anhydrite and celestite samples plot close to or below the macrofossil age-depth trend for each locality, indicating formation from waters preserving seawater Sr-87/Sr-86 approximately contemporaneous with or slightly younger than the time of sediment deposition. Local deviations from this trend are interpreted as indicating episodes of seepage-reflux and also a contribution of Sr from non-marine sources during formation of the Gachsaran cap rock anhydrite.

A compilation of average porosity and permeability data for petroleum reservoirs in the Permian–Triassic Khuff Formation and the Jurassic Arab Formation shows that most Khuff reservoirs have an average porosity of less than 12%, whereas most Arab reservoirs have an average porosity of 12–26%. Higher porosity correlates with shallower depth, suggesting that burial diagenesis is the main cause of the overall porosity difference between these units. Deeper burial of Khuff reservoirs is inferred to have resulted in greater porosity loss by chemical compaction and associated cementation. A broad correlation also exists between average porosity and average permeability, suggesting that deeper burial and the resulting porosity decrease are also a primary cause of the lower permeabilities of the Khuff reservoirs. In addition to greater burial depth, however, a combination of depositional and early diagenetic factors is also reflected in the lower average porosity and permeability values of the Khuff reservoirs. Khuff strata were deposited on an extensive, poorly circulated, very low-relief shelf and consist in large part of interbedded mudstones and grainstones having relatively fine grain size, with major amounts of depositional calcium sulfate present. Arab reservoirs were deposited under better circulated conditions near platform margins facing deep, intracratonic basins and, thus, have coarser, more grain-dominated fabrics and lesser overall content of chemically precipitated grains, calcium sulfate, and dolomite. Khuff deposits were likely composed of less stable mineralogy than Arab sediments because the Late Permian was a time of aragonite seas, whereas the Late Jurassic was a time of calcite seas. The combined result of these factors is that Arab reservoirs are characterized by greater preservation of primary depositional pore types, more coarsely crystalline dolomite fabrics, and lesser plugging by anhydrite. Finally, a possible factor affecting the average porosity and permeability values is petroleum composition, which is gas in most Khuff reservoirs and oil in Arab reservoirs. Lower economic cutoff values for gas production would favor inclusion of low-permeability zones in Khuff reservoirs, thus reducing average reservoir values. Two main aspects of these results are innovative. This is the first time that porosity and permeability values for either Khuff or Arab reservoirs have been examined regionally. Second, the conclusion that thermal exposure is the primary control on average porosity and permeability in these units is consistent with previous work from other carbonates, but is new for the Middle East.

A comprehensive geological and petrophysical dataset from Upper Shu’aiba clinoform bodies in northwest Oman has been used for reservoir characterization, understanding the factors determining reservoir quality, and reservoir rock typing. Lithofacies are grouped into three main facies belts, showing increasing bioclast proportions and size both upwards within each clinoform and towards the basin margin. Most lithofacies are mud-rich, with even the coarsest floatstones and rudstones containing abundant mud matrix between rudist, sclerosponge, and coral clasts. Total porosity is strongly partitioned between the lower and upper hemicycles of each clinoform and also increases towards the basin margin. Wide porosity variations within each lithofacies reflect control of porosity loss by clay abundance, as reflected in overall inverse correlation between total porosity and bulk-rock alumina content. Reservoir rock types with meaningful differences in both porosity-permeability transforms and MICP parameters were defined by applying porosity cut-offs at an arbitrary value of 20% to the three main lithofacies. Because both lithofacies and porosity are predictably related to the sedimentological and stratigraphic organization within the clinoform bodies, the RRT thus defined can potentially be implemented for assigning specific ranges of petrophysical properties throughout a reservoir model.

This paper reports a series of 700 porosity–permeability analyses and supporting petrographic and sedimentologic descriptions from Early to Late Miocene carbonate strata cored on the Marion Plateau, offshore from north-eastern Australia, during Ocean Drilling Program (ODP) Leg 194. The samples analysed are not only mainly coarse bioclastic limestones and dolomitized equivalents from platform-top facies, but also include 79 plugs from deeper-water slope to hemipelagic drift facies. Outstanding characteristics of this data set are the wide ranges of porosity and permeability in both limestones and dolostones, the large degree of short-range heterogeneity typical of these strata, and the better porosity–permeability correlation of dolostones than limestones. The platforms have experienced widely varying calcite cementation, dolomitization and dissolution but show little clear evidence of meteoric diagenesis, suggesting that subaerial exposure may have played little role in porosity–permeability evolution. Permeability-for-given-porosity is controlled by grain size and calcite cement content in grainstones and by occurrence of larger shelter pores and vugs in mud-rich samples. Dolomitization tends to reduce the variation of permeability-for-given-porosity by recrystallizing mud matrix to form intercrystalline macroporosity that connects vugs and moulds to become integrated with the effective pore system. As a result, there are no differences in permeability–porosity trends for different dolostone textures, whether dominated by intercrystalline, vuggy, or preserved intergranular pore types. Two platform-top sites separated by only 5 km display a major lateral variation in dolostone porosity–permeability characteristics within the youngest dolostone units. This difference is interpreted as reflecting a relatively ‘windward’ (current-facing) setting of the site with the overall higher permeability-for-given-porosity (Site 1199) that led to less muddy depositional facies, greater cementation, and lesser grain dissolution. Pore-geometry parameters measured by petrographic image analysis confirm that the ‘windward’ dolostones have pores that are both larger and less intricate than dolostones comprising the more current-protected location.

Dolomitisation is an important factor controlling reservoir quality in the Asmari Formation in many producing fields in SW Iran. Dolostones have higher average porosities than limestones. Petrographic and geochemical studies have been used to determine the causes of Asmari dolomitisation at the Bibi Hakimeh and Marun fields and at the Khaviz anticline. The formation is generally characterized by a large-scale trend of upward-decreasing accommodation. Basal strata were deposited under relatively open-marine, high-energy conditions, whereas the Middle to Upper Asmari succession was deposited in relatively protected settings with more frequent evidence of exposure and evaporitic conditions. There is a general upward increase in the abundance of both anhydrite (occurring as nodules and cement) and dolomite. Two main types of dolomite fabric are recognised, reflecting the textures of the precursor limestones: (1) finely crystalline pervasive dolomite (commonly

The important thing to understand about carbonate diagenesis is not how porosity is created, but how it is destroyed. Detailed core observations from two deeply-buried carbonate platform successions (the Finnmark platform, offshore north Norway; and the Khuff Formation, offshore Iran) show that in both cases most vertical porosity variation can be accounted for by only two or three factors, namely: (1) stylolite frequency, (2) proportion of argillaceous beds, and (3) anhydrite cement. The spatial distribution of these factors is determined by the depositional distribution of clay minerals (important for localizing chemical compaction) and the occurrence of hypersaline depositional conditions and associated brine reflux (important for localizing anhydrite precipitation and dolomitisation). However, the intensity of chemical compaction and consequent porosity loss in adjacent beds by carbonate cementation also depend upon thermal exposure (temperature as a function of time). Evidence from the Finnmark platform and other examples indicate that the stratigraphic distribution of early-formed dolomite is also important for porosity preservation during burial, but this factor is not apparent in the Khuff dataset. Insofar as the Finnmark and Khuff platforms can be regarded as representative of carbonate reservoirs in general, recognition of the above porosity-controlling factors may provide the basis for general models predicting carbonate reservoir potential both locally (reservoir-model scale) and regionally (exploration-scale). Distributions of clay, anhydrite, and dolomitization should be predictable from stratigraphic architecture, whereas variations in thermal exposure can be mapped from basin analysis. In the present examples at least, factors that do not need to be considered include eogenetic carbonate cementation and dissolution, depositional facies (other than aspects related to clay and anhydrite content), and mesogenetic leaching to create late secondary porosity.

Strontium-isotope stratigraphy has been used to examine the timing of depositional events and dolomitization in two Miocene carbonate platforms cored by Ocean Drilling Program (ODP) Leg 194, just seaward of the Great Barrier Reef. The results provide firm constraints for correlating surfaces and depositional stages between the two platforms and thereby relating seismic sequences previously defined in the off-platform sediments to the lithostratigraphic units described from cores in the seismically transparent platform-top sites. Oyster-bearing beds at the base of both platform successions yield early Oligocene ages (29–31 Ma), thus dating initial transgression of the Marion Plateau's volcanic basement. There followed a period of slow accumulation of shallow-water grainstones rich in quartz and phosphate grains in late Oligocene time (29–23 Ma; seismic Megasequence A). The main growth of the carbonate platforms took place in early to late Miocene time (23–7 Ma), comprising five depositional sequences. The first four of these (seismic Megasequence B) are common to both platforms and terminated with a possible karst surface at 10.7 Ma. Different sedimentologic expression of this megasequence in the two platforms reflects contrasting progradational versus aggradational geometries in the locations studied. The final growth stage (seismic Megasequence C) occurred only in the southern platform and terminated at 6.9 Ma. Both platform-demise events (10.7 and 6.9 Ma) approximately coincide with falls in global sea level combined with longer-term trends of decreasing water temperature. Sr-isotope ages of dolostones increase with depositional age, and older dolostones in the southern platform have more coarsely crystalline and fabric-destructive textures than overlying younger dolostones. These relationships are consistent with dolomitization by normal seawater shortly after deposition and overprinting of multiple times of dolomite recrystallization and cementation in the deeper strata.

Porosity and permeability data from five carbonate platform successions of different settings, ages, and burial depths are examined to identify overall similarities and differences in the reservoir quality of interlayered limestones and dolostones. Each succession consists mainly of limestone and dolostone, with subordinate proportions of intermediate, partly dolomitized compositions. In the three deeply buried platforms, the key features are that limestones have much lower average porosity than associated dolostones, and that limestones and dolostones show little difference in average permeability-for-given-porosity. In contrast, the shallowly buried platforms show little difference in average porosity between limestones and dolostones and also display higher average permeability-for-given-porosity in dolostones than limestones. These data suggest the following general guidelines for depositional and diagenetic controls on reservoir architecture in carbonates consisting of interlayered limestone and dolostone. (1) Reservoir compartmentalization by the formation of tight limestone barriers is largely a burial diagenetic process involving calcite cementation locally produced by chemical compaction. (2) Both the pattern of early dolomitization and the distribution of clay minerals (because they influence the localization of chemical compaction) are key factors that determine the distribution of tight limestone barriers separating flow units. Thus, the pattern of eventual burial compartmentalization follows a template that is hardwired into the stratigraphic architecture by depositional mineralogy and early diagenesis. (3) After burial (2–3 km; 1.2–1.8 mi), dolostones should not be expected to have higher permeability-for-given- porosity than associated limestones. These rules assume dolomitization to occur early relative to chemical compaction, which will commonly be the case because of combined hydrologic and mass-balance constraints. Dolomitization and concentration of clay appear linked to cycle and sequence architecture in the present examples and thus may have a useful degree of predictability, at least in terms of statistical parameters, such as net/gross and probability of flow-unit thickness distribution.

Plots are presented comparing average porosity vs. depth for 30,122 siliciclastic petroleum reservoirs and 10,481 carbonate petroleum reservoirs covering all petroleum-producing countries except Canada. However, separate plots cover 5534 siliciclastic and 2830 carbonate reservoirs of the Alberta basin in Canada. Average permeability vs. average porosity is shown for the non-Canadian reservoirs. Key similarities and differences between sandstones and carbonates are noted, and implications are discussed regarding the dominant factors controlling reservoir quality in each lithology. Trends of steadily decreasing median and maximum porosity with increasing depth reflect burial diagenetic porosity loss in response to increasing thermal exposure with depth. These trends seem inconsistent with the suggestions that both sandstones and carbonates commonly increase in porosity by dissolution during deeper burial. Carbonate reservoirs have lower values of median and maximum porosity for a given burial depth, probably because of greater chemical reactivity of carbonate minerals relative to quartz and the resulting lower resistance to chemical compaction and associated cementation. Relative paucity of low-porosity (0–8%) siliciclastic reservoirs at all depths compared with carbonates may reflect the more common occurrence of fractures in carbonates and the effectiveness of these fractures for facilitating economic flow rates in low-porosity rock. Overall, carbonate reservoirs do not have lower permeability for a given porosity compared with sandstones but do have strikingly lower proportions of both high-porosity and high-permeability values. The data presented can serve as a general guide for the distribution of reservoir quality that can reasonably be expected in exploration wells drilled to any given depth in the absence of detailed geologic information, such as burial and thermal history.

Many authors have proposed that significant volumes of porosity are created by deep-burial dissolution in carbonate reservoirs. We argue, however, that this model is unsupported by empirical data and violates important chemical constraints on mass transport. Because of the ubiquitous presence and rapid kinetics of dissolution of carbonate minerals, the mesogenetic pore waters in sedimentary basins can be expected to be always saturated and buffered by carbonates, providing little opportunity for the preservation of significantly undersaturated water chemistry during upward flow, even if the initial generation of such undersaturated pore water could occur. A review of the literature where this model has been advanced reveals a consistent lack of quantitative treatment. In consequence, the presumption of mesogenetic dissolution producing a net increase in secondary porosity should not be used in the prediction of carbonate reservoir quality.

A 300-m (1000-ft)-thick succession of shallow- and warm-water carbonates has been studied in well cores from the southernmost Barents Sea, offshore north Norway. These upper Paleozoic strata contain numerous zones of moderate to high porosity, including a wide range of depositional facies, despite moderately high burial temperatures and the absence of petroleum charge. Most porosity appears to be either primary or created during early (eogenetic) diagenesis. Negative correlation between porosity and both bulk-rock alumina content and stylolite frequency reflects the influence of phyllosilicate minerals in localizing stylolitic dissolution. This provides part of the explanation for the overall correlation between porosity and the platform's stratigraphic evolution. The early stage of mixed siliciclastic-carbonate deposition has low porosity because of extensive chemical compaction in aluminous beds. The following siliciclastic-poor stage shows upward-increasing porosity associated with aggradation of muddy buildups and wackestones, followed by the progradation of a more proximal facies belt of thinly bedded dolomitic mudstones. Maximum porosity development occurs in the overlying, little-dolomitized grain-shoal facies belt, which shows upward decrease in porosity because of a transgressive trend that developed progressively lower energy depositional conditions, favoring the occurrence of stylolite-prone shaly laminations. A general porosity-favorable factor is the presence of a stratified column of high-salinity brine, enforcing a closed diagenetic system during burial. Limestones and dolostones comprising this platform have very different proportions of low and high porosity values. Limestones have positively skewed frequency distribution (many samples

Sandstone reservoirs from the Norwegian continental shelf commonly show varying degrees of postdepositional fractionation of Sm/Nd ratio, apparently due to preferential incorporation of Sm in the crystal lattice of diagenetic apatite. Based on data from leaching experiments, an apatite mineral separate, and petrography, it is proposed that fractionation occurred mainly during closed-system burial diagenesis, as phosphate deposited on the sea floor recrystallized to apatite and incorporated rare earth elements (REE) from the surrounding rock matrix. As a result, the Sm-Nd model age parameter in general contains two components of information: A) the true crustal age of the sediment and B) a secondary component of Sm/Nd fractionation, which can be either negligible or dominant. It is difficult to separate these components and thus correct for component B. Even in data showing no obvious signs of postdepositional fractionation, model ages may be variably disturbed by subordinate amounts of diagenetic alteration. However, the isotope ratio 143Nd/144Nd is expected to be relatively resistant to alteration by secondary Sm/Nd fractionation and should therefore be used rather than model age as the principal correlation parameter in stratigraphic studies. In this way, Nd-isotope stratigraphy can still be used as a valuable and unique tool for studies of provenance and correlation, even in strata showing strong Sm/Nd fractionation effects. Strongly Sm/Nd-fractionated horizons (recognized by bulk-rock Sm/Nd ratios > 0.23) may also be useful for stratigraphic correlation, but it is clear that their occurrence reflects special depositional conditions rather than shifts in sediment provenance.

Brent Group sandstones from the north side of the Gullfaks Oilfield contain mostly 5–8% albitic plagioclase, whereas plagioclase is almost absent in the same strata in the southern part of the field. Absence of plagioclase throughout the entire vertical extent of the Brent Group in the southern wells seems to rule out provenance as the principal explanation for differing plagioclase content, which is therefore interpreted as the result of diagenesis. Hypotheses for the nature of the inferred leaching event include epigenetic meteoric diagenesis and mesogenetic release of acid components from clay minerals or kerogen, but these explanations are unable to account for the observed spatial distribution of the plagioclase-bearing and plagioclase-free sandstone intervals. However, overall correspondence between the area lacking plagioclase and oil compositions having both anomalously high CO2 and organic geochemical indications of advanced biodegradation suggest a link between plagioclase dissolution and biodegradation of the present oil column. It is, therefore, proposed that acid components from biodegradation selectively reacted with albitic plagioclase to form kaolin, releasing sodium bicarbonate into the residual water. The plagioclase-free sandstones contain more kaolin than the plagioclase-bearing sandstones, as would be expected due to aluminium conservation. However, the wide and overlapping ranges of kaolin content in both groups suggest that most of the kaolin originated from processes other than biodegradation-driven plagioclase alteration, potentially including both epigenetic and mesogenetic dissolution, as well as deposition of detrital kaolin and kaolin precursors.

The Nd isotopic composition of core samples from the mid-Carboniferous to Upper Permian Finnmark carbonate platform is interpreted as representing their siliciclastic content, the Nd content of the carbonate fraction being relatively insignificant. Trends of upward increase in 143Nd/144Nd in these strata correlate with the two largest-scale (second-order) depositional sequences defined by previous sedimentologic study. These trends are interpreted as the result of mixing between two hypothetical siliciclastic provenance terranes. The relatively “old” (low 143Nd/144Nd) material dominating the base of each cycle is suggested to be derived from local Caledonian basement. The relatively “young” (high 143Nd/144Nd) material comprising the upper part of each cycle is suggested to be an open-marine siliciclastic composition representing mixing of more widespread sources. Dominance of the basement provenance signature at the base of each second-order sequence could reflect tectonic movements that exposed local basement areas to erosion. The subsequent gradual shift to “younger” open-marine provenance signature could result from progressive peneplanation or burial of the basement uplifts. Higher-frequency depositional sequences have little to no effect on Nd composition, suggesting that these fluctuations in facies distribution were largely unrelated to patterns of siliciclastic supply. This model implies that the mid-Asselian second-order lowstand was a time of major siliciclastic bypass, suggesting the possible existence in the Nordkapp Basin of extensive sandstones of this age. The observed pattern of cyclic, asymmetric 143Nd/144Nd variation should be a universal characteristic of Finnmark platform stratigraphy and may therefore be useful for stratigraphic correlation between widely separated well locations. The broader interest of these results is the demonstration that: (1) the Nd isotopic composition of even relatively pure carbonate rocks can reflect mainly the provenance signature of the siliciclastic component; and (2) Nd isotopic profiling of carbonate strata can indicate patterns of tectonic influence on depositional cyclicity.

A new set of descriptions has been prepared for five of the IKU cores, a series of shallow stratigraphic cores penetrating the Upper Carboniferous-Permian Finnmark carbonate platform succession near its southern erosional truncation against the Norwegian mainland. These data are compared with core descriptions previously published from the thicker 'stratigraphic reference section' of the exploration well 7128/6-1 (Ehrenberg et al. 1998a). New fusulinid datings from 7128/6-1 are correlated with existing fusulinid data from the IKU cores to provide a consistent time-stratigraphic framework for landward correlation of depositional sequences previously defined in the 7128/6-1 reference section. These correlations reveal a limited two-dimensional image of depositional sequence geometry for the inner platform. Of the 7 major sequences previously defined in the Kasimovian through Upper Permian section of well 7128/6-1, 2 sequences are suggested to pinch out before reaching the IKU cores, while the remaining 5 se...

Abstract Core samples from 10 wells in Lower Cretaceous limestones of the Upper Shu'aiba Formation were characterized by conventional core analyses, petrography, bulk chemical analyses, and mercury injection capillary pressure data to define reservoir rock types (RRT) for input to reservoir modeling. Initial grouping by lithofacies allows linkage of rock types to a 3D geological model, but results in RRT with high degrees of overlap in petrophysical properties. When diagenesis is included, however, in the form of porosity cut-offs added to the lithofacies criteria, RRT can be defined having both 3D geological significance and distinct ranges of pore-throat size distribution. The use of total porosity as a rock typing criterion is based on the interpretation that porosity is controlled on reservoir scale by depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms have low clay and thus highest porosity. Although most of the pore space is microporosity, higher total porosity corresponds with higher proportions of macropores and probably also with greater frequency of open fractures, resulting in better permeability. High-porosity samples also have several systematic positive differences in MICP characteristics from lower-porosity samples of the same lithofacies. Because both lithofacies and porosity are related to the sedimentological and stratigraphic organization of the Upper Shu'aiba clinoforms, the RRT defined by these criteria can potentially be implemented in a reservoir model for assigning particular ranges of petrophysical properties to distinct portions of each clinoform. By this procedure, seven RRT have been defined in the present selection of samples.

Core samples from 10 wells in Lower Cretaceous limestones of the Upper Shu'aiba Formation were characterized by conventional core analyses, petrography, bulk chemical analyses, and mercury injection capillary pressure data to define reservoir rock types (RRT) for input to reservoir modeling. Initial grouping by lithofacies allows linkage of rock types to a 3D geological model, but results in RRT with high degrees of overlap in petrophysical properties. When diagenesis is included, however, in the form of porosity cut-offs added to the lithofacies criteria, RRT can be defined having both 3D geological significance and distinct ranges of pore-throat size distribution. The use of total porosity as a rock typing criterion is based on the interpretation that porosity is controlled on reservoir scale by depositional clay content of the local stratigraphic environment. The seaward and uppermost parts of the clinoforms have low clay and thus highest porosity. Although most of the pore space is microporosity, higher total porosity corresponds with higher proportions of macropores and probably also with greater frequency of open fractures, resulting in better permeability. High-porosity samples also have several systematic positive differences in MICP characteristics from lower-porosity samples of the same lithofacies. Because both lithofacies and porosity are related to the sedimentological and stratigraphic organization of the Upper Shu'aiba clinoforms, the RRT defined by these criteria can potentially be implemented in a reservoir model for assigning particular ranges of petrophysical properties to distinct portions of each clinoform. By this procedure, seven RRT have been defined in the present selection of samples.

Core and log data from Lower Cretaceous limestones of the Upper Shu'aiba (US) Member in northwestern Oman were examined for evidence of diagenesis related to the top surface where this reservoir is overlain by shale of the Nahr Umr Formation. Cores from six vertical wells in three oilfields were studied by profiles of conventional core analyses, petrographic observations, and bulk-rock geochemical analyses. Neither bulk-carbonate stable-isotope analyses nor bulk-rock strontium concentrations show trends indicative of upward-increasing meteoric diagenesis below the top-US surface. Porosity and permeability data also show neither increasing nor decreasing vertical trends suggestive of surface-related diagenesis. Meteoric leaching and cementation may nevertheless be pervasive throughout the US reservoirs, at least partially accounting for extensive aragonite dissolution and filling of the resulting macropores with coarse calcite cement. Three of the cores show trends of upwards-increasing bulk-rock iron, manganese, phosphorous, and uranium. These effects are attributed to sea-floor authigenesis driven by reducing conditions within the upper several meters of sediment following each cycle of US sedimentation. In addition, the top 7 m of limestone in one of the cores contains several percent late saddle dolomite, and minor saddle dolomite also occurs near the tops of several other cores. Mg for dolomitization can have been provided from diagenesis of clay in the Nahr Umr Formation. The results of this study thus indicate both early sea-floor mineralization and late dolomitization in some places below the top-US surface, but do not confirm locally more intense meteoric diagenesis underlying this surface.

Thin zones of asphaltene-rich residue are present near the crests of two adjacent oil- and gas-filled structures. In one structure, the Smorbukk Sor Field, multiple thin (5–50 cm) dark coloured zones are observed within the lower 20 m of the 88 m thick Garn Formation. These dark coloured zones tend to occur immediately above stylolitized mica-clay laminations and become gradually lighter upwards, apparently reflecting gradual upward decrease in residue abundance. In the other structure, the Smorbukk Field, the lowermost 1 m of the formation is dark coloured and the sandstone gradually becomes lighter in colour upwards for a distance of about 3 m. Similar, but more diffuse, residues are also present throughout the oil zone in two other fields nearby. Organic geochemical analyses show that the residue-rich (dark coloured) zones differ from the sorrounding lighter coloured sandstone mainly in having a higher content of asphaltenes, whereas the total content of extractable organic matter is often similar. Thus the darker rocks might be regarded more as zones of conspicuous oil staining due to asphaltene deposition, rather than as small tar mats. The residues typically appear to have accumulated under the influence of gravity at points where the downward flow was hindered by a lithological discontinuity. Present day zonation (upward-decreasing gas to oil ratio) in the oil column of the Smorbukk Sor reservoir is consistent with a model of asphaltene precipitation in the lower part of the reservoir in response to upward leakage of gas from an underlying gas condensate reservoir in the Ile Formation. This is also consistent with the available organic geochemical data. In thin section, the asphaltene-rich material is seen to preferentially coat feldspar and clay but not quartz surfaces, thus illustrating why sandstone wettability should be expected to depend on both mineralogy and the asphaltene content of the petroleum involved.

Replacement of kaolinite by dickite has been observed to occur with increasing depth of burial in sandstones from three different basins on the Norwegian continental shelf. In the Garn Formation (Middle Jurassic) of Haltenbanken, samples from 1.4-2-7 km below the sea floor (110°C) contain kaolinite, whereas deeper than 3.2 km (130°C) mainly dickite is present. In the Statfjord Formation (Late Triassic-Early Jurassic) from Gullfaks and Gullfaks Sør Fields, transformation of kaolinite to dickite occurs at ~3.1 km below the sea floor (120°C) From the Stø and Nordmela Formations (Lower to Middle Jurassic) to the Troms Area, kaolin polytypes have been identified in only two shallow and two deep samples, but the results are consistent with the transformation depth determined in two other areas studied. These occurrences are significant because they allow the temperature of the kaolinite/dickite transformation to be established with greater confidence than had been possible previously. Also the observation of this transformation in all three areas so far examined indicates that it may be a general and predictable feature of kaolinbearing sandstones worldwide and therefore a potentially reliable paleogeothermometer. In most cases, the kaolinite occurs as relatively large vermicular crystals, whereas dickite forms more euhedral, blockier crystals. This morphological difference, together with the nature of the structural difference in octahedral occupancy between the kaolinite and dickite, suggests that the transformation occurs by dissolution and reprecipitation, rather then in the solid state.

International audience; This study is based on rock mechanical tests of samples from platform carbonate strata to document their petrophysical properties and determine their potential for porosity loss by mechanical compaction. Sixteen core-plug samples, including eleven limestones and five dolostones, from Miocene carbonate platforms on the Marion Plateau, offshore northeast Australia, were tested at vertical effective stress, View the MathML source, of 0–70 MPa, as lateral strain was kept equal to zero. The samples were deposited as bioclastic facies in platform-top settings having paleo-water depths of