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The Eocene sandstones in the northern Dongying Sag, Bohai Bay Basin, China, are reservoirs for large accumulations of hydrocarbons. The sandstones are mainly lithic arkoses and feldspathic litharenites, texturally and compositionally immature. These sandstones have a wide range of porosity (0.4–37%) and permeability (0.004–6969 mD) and show an overall decrease in reservoir quality from 1500 m to 5000 m below sea level. The reduction in reservoir quality is a product of several digenetic processes; these include compaction, precipitation of dolomite and calcite in eodiagenetic stage; compaction, feldspar dissolution, precipitation of quartz cements and clays (kaolin and illite) and precipitation of ferrocalcite and ankerite in mesodiagenetic stage. Mineral distribution pattern and isotopic composition suggest carbonate cements in sandstones originate from sources outside the sandstones. Carbonate cementation, together with compaction reduced the sandstones’ porosity and permeability significantly. In a sandstone bed, marginal sandstones with distance to sandstone/mudstone interface less than one meter always have lower porosity than central sandstones. As burial depth exceeds 4000 m, marginal sandstones have very low porosities ( 2 m) can be potential effective reservoirs. Feldspar dissolution and precipitation of clays and quartz cements have little impact on absolute porosity. Mineral distribution pattern and quantitative data show that leached feldspars are the internal source of authigenic quartz and clays in sandstones, and the volume difference between feldspar secondary porosity and related authigenic cements is generally less than 0.25%. However, although there is little or no net import of matter to the sandstones, the pore architecture changes dramatically. Primary macropores are lost as clays and quartz precipitate while the proportion of microporosity increases, occurring mainly between clay crystals. The overall result is that permeability is significantly degraded.

As the exploration of hydrocarbons moves into more complex and deeper basinal settings the need to understand the effect of high temperatures and high pressures on reservoir quality and rock properties becomes even more important. The fluvial channel sandstone reservoirs of the Skagerrak Formation in the Central North Sea exhibit anomalously high porosities and permeabilities considering their depth of burial (>3500 m below sea floor). Despite the complex depositional setting, diagenetic history, high overpressure and temperatures encountered in the Skagerrak Formation, hydrocarbons are currently being produced. The Skagerrak Formation reservoirs used in this study have encountered overpressures of >40 MPa and temperatures up to ∼185 °C at present day maximum burial. To identify the role played by the high pressure and high temperature encountered in the reservoir sandstones a multidisciplinary approach involving petrographic, fluid inclusion, and burial history modelling studies has been adopted. Our interpretation of the results is that the generation of shallow overpressure in these fields limited mechanical compaction and also played an important role in minimizing pressure solution in the chemical compaction regime as evidenced by reduced quartz cementation. Fluid inclusions found in the quartz overgrowths indicate late-stage development with temperatures of formation in the range 130 to 170 °C coincident with late-stage deeper burial. Hydrocarbon emplacement occurred after quartz cementation and has had little to no effect on porosity preservation. The formation of well-developed authigenic chlorite (>70% surface coating) and, to a lesser extent illite clay coats with burial had a positive effect on porosity preservation even though permeability was marginally reduced in the illite-rich sandstones. A schematic porosity and quartz cement evolution model has been developed which allows for pre-drill prediction of reservoir quality in the Heron Cluster and provide valuable insights for other complex high-pressure high-temperature reservoirs.

In the current debate on the ability of oil emplacement to halt quartz cementation in sandstone oil reservoirs, this paper supports a "yes, it can" answer. Although we find some of the empirical data petroleum fluid inclusion abundances, quartz-depth trends) to be inconclusive, we have made progress in this debate by examining theoretical controls for three end-member quartz cementation scenarios. (1) Silica externally sourced via advection. Oil emplacement must halt quartz cementation because of the associated massive reduction in relative permeability to water. (2) Silica supplied internally, water-wet reservoir. Quartz cementation will be inhibited because the rate of diffusion will be reduced by orders of magnitude, making diffusion the rate controlling step. The degree of inhibition will depend on rock fabric and oil saturation; at very high oil saturations quartz cementation could effectively cease. (3) Silica supplied internally, oil-wet reservoir. Quartz cementation will be halted as water cannot access to grain surfaces.

The relative importance of petroleum emplacement in inhibiting diagenetic processes and preserving porosity and permeability in Lower Cretaceous, Thamama Group (Kharaib Formation) carbonate reservoirs of Abu Dhabi, UAE, and in Callovian-Kimmeridgian carbonate reservoirs of the Amu Darya Basin in Uzbekistan and Turkmenistan, has been evaluated by combining geologic, petrophysical and geochemical data. When petroleum emplacement is synchronous with and prior to significant burial cementation in carbonates, primary petroleum inclusions are trapped in the cements. The process appears to be characterised by steep intra-field porosity-depth trends within a more gradual regional decline in porosity with depth. This has profound implications for the prediction of porosity in carbonate reservoirs. Reservoir quality is better in grainstones and packstones compared to adjacent wackestones and lime mudstones in the Kharaib Formation because of preserved macroporosity (intergranular, vuggy, mouldic); the pore system in the finer units is dominated by micropores. These features indicate a primary textural control on porosity and permeability. Within the grainstones and packstones, macroporosity is variably filled by late equant sparry calcite cements. Porosity and permeability variations in grainstones and packstones at a reservoir scale are therefore controlled by the variation in amount of equant sparry calcite cement. This in turn depends on the timing of the precipitation of this cement relative to petroleum emplacement, as shown by fluid inclusion data. Where petroleum emplacement has occurred relatively early, at migration foci, prior to significant burial cementation by equant sparry calcite, reservoir quality is preserved. Where it has occurred after significant burial cementation, reservoir quality has been destroyed. In the Amu Darya sequences, primary macroporosity is commonly preserved down to depths of 11,000 ft (3.5 km) with differences in the porosity and permeability characteristics of grainstones being controlled by variations in the amount of early, probably freshwater, cement and the extent of associated dissolution. Small volumes of burial cements do occur, but they do not contain petroleum inclusions. Consequently, there is no firm evidence that petroleum emplacement has inhibited diagenesis in this area. This part of the study has shown that it is not always possible to obtain conclusive evidence from the diagenesis to pin down the processes responsible for the preservation of reservoir quality and that petroleum filling may not always be the primary cause. The relationships documented here show that the ‘race for space’ between diagenetic waters and petroleum is a major control on reservoir quality in the Thamama Group carbonate reservoirs, but is not so important for the Jurassic carbonates in the Amu Darya basin.

The Chalk Group (Cretaceous/Tertiary) in the Machar Field (British North Sea) contains both fracture-filling and microcrystalline calcite cements. Modeling of fluid-rock interaction using data on light stable isotopes obtained by whole rock analyses and laser ablution analyses of calcite cements reveal that the fracture and matrix diagenetic systems were largely decoupled. The calcium and carbonate of the fracture-filling calcite cements were derived largely from the adjacent chalk matrix. The fracture diagenetic system had a high water-rock ratio, which maintained a relatively stable water 18O ratio during calcite dissolution and precipitation. The chalk matrix on the contrary, had a low molar water-rock ratio during r crystallization, which resulted in increases in the pore-water 18O value during recrystallization at elevated temperatures. This evolution of the pore-water 18O value is manifested by highly variable cement 18O values. The present-day formation waters of the Machar Field have 87Sr/86Sr ratios significantly higher than the whole rock and fracture-filling cement calcite values, evidence that the chemical composition of the formation waters is not representative of that of the pore waters during chalk recrystallization. Little diagenesis is therefore now occurring in the Machar Field. The diagenetic systems of the chalk matrix and fractures both had a high degree of openness with respect to carbon, because of the introduction of organically derived bicarbonate rather than advection of water through the chalk. The hulk of calcite cementation in fractures and the recrystallization and cementation of the chalk matrix occurred at temperatures in the 80-100°C range, at or just belo the present-day reservoir temperature of 97°C.

We present a model that explains the patterns of sandstone burial diagenesis in certain oil reservoirs, in which petroleum migration and burial cementation were synchronous. The coincidence of these two processes controls the chemistry and distribution of major burial cement phases across the field, which in turn controls the distribution of reservoir quality, causing a rapid decline of porosity and permeability with depth. Such a rapid poroperm deterioration is observed in many North Sea sandstone oilfields; we highlight the Magnus Sandstone Member of the Magnus Oilfield, northern North Sea as a type example of such a reservoir. The two most significant elements of the synchronous cementation and migration model are that burial cementation in the reservoir occurs over a restricted time interval, probably less than 10 Ma and that rapid and widespread fluid circulation is not invoked to explain the concentrations of cements observed. We speculate that cementation takes place at, and in a series of zones below, the oil-water contact which descends as oil fills the reservoir, with little change to the bulk chemistry of the reservoir formation waters through time.

When a reservoir fills with petroleum, the process commonly takes about 10 Ma. Cementation of a sandstone reservoir can occur in a similarly short time. There is much direct evidence that these two processes can occur at about the same time. In petroleum-bearing sandstone reservoirs it is common to find inclusions of petroleum trapped in diagenetic minerals. The effect on reservoir porosity and permeability caused by the interaction of these two processes is dramatic. Fields with a relatively early petroleum charge, earlier that is than cementation, can be saved from the ravages of reservoir quality destruction. Fields in which the two processes were acting at the same time commonly display porosity-depth gradients which are twice the regional average. If cementation beats petroleum in this ‘race for space’ there may be no field to produce, as the petroleum may not be recoverable from the low quality reservoir. We believe that the processes of petroleum generation/migration and cementation may share a common cause. Both processes are commonly associated with major changes within a basin: rapid burial/heating of the sediment pile and/or major faulting which changes the basin ‘plumbing’.

The temperature of quartz cementation in Mesozoic sandstones from the Haltenbanken area, offshore mid-Norway has been evaluated by micro-thermometry of primary aqueous fluid inclusions in quartz overgrowths. Samples were collected from a wide range of burial depths (1.6 to 4.4 km) and large area (7500 km 2 ). There is a systematic increase in homogenization temperatures ( T h ) of approximately 75 °C between the shallowest and deepest wells. When converted to time using burial histories, the T h data indicate that cementation was short-lived and started roughly synchronously throughout Haltenbanken within the last 5 Ma. It therefore seems that depth and/or temperature alone are not enough to bring about quartz cementation, some other factor(s) must also be involved.

Sandstones that share common detrital mineralogies, depositional environments, and burial histories also share common diagenetic histories. A survey of the diagenetic history of 100 sandstones from around the world has recognized five common, repetitive, and predictable styles of diagenesis in which similar diagenetic mineral assemblages have been observed. The five diagenetic styles are: (1) quartz, commonly with lesser quantities of neoformed clays (e.g., kaolinite and/or illite) and late-diagenetic, ferroan carbonate; (2) clay minerals (illite or kaolinite) with lesser quantities of quartz or zeolite and late-diagenetic carbonate; (3) early diagenetic (low-temperature) grain-coating clay mineral cements such as chlorite, which may inhibit quartz cementation during later burial; (4) early diagenetic carbonate or evaporite cement, often localized, which severely reduces porosity and net pay at very shallow burial depths; and (5) zeolites, which occur over a wide range in burial temperature, often in association with abundant clay (usually smectite or chlorite) and late-diagenetic, nonferroan carbonates. End_Page 61------------------------- The quartz diagenetic style is the most common and accounts for 40% of the sample set. It is also most likely to occur in mineralogically mature sandstones, while early diagenetic carbonates and zeolites dominate in mineralogically immature sandstones. Presence or absence of clay appears to be independent of both initial sand mineralogy and depositional environment. However, when clay is present, the type appears to vary as a function of initial sand mineralogy and depositional environment. Large quantities of quartz are unusual cements in sequences that have never been hotter than 75°C, while illite precipitation at temperatures below 100°C is rare. Zeolite composition changes systematically from clinoptilolite at 25°C to laumonite at temperatures >100°C. The repetitive nature and simplicity of these five styles can help predict modifications in reservoir quality due to burial. An accurate prediction of the reservoir quality in sandstones forms the basis of an accurate porosity and permeability prediction ahead of drilling wells in petroleum exploration, development, or production.

The Miocene Sihapas Formation sands of the Central Sumatra Basin (Indonesia) are being cemented by quartz, clay, and carbonate minerals, today. Precipitation of these minerals in the pore spaces has reduced the porosity of the sandstones from 30% to 20%. Four independent sets of data are interpreted to show that cementation began only 2 million years ago and that it is active today: A major reverse fault split a once continuous Sihapas sandstone about two million years ago. In the hanging wall of the fault the Sihapas sand is uncemented. In the footwall the same sandstone is cemented. Compaction-induced porosity loss in these sandstones is the same as that expected for the present burial depth of the sandstones. The temperature at which quartz cement precipitated is the same as the present-day formation temperature. Water trapped within fluid inclusions in the quartz cement is of similar low salinity to the formation water, and the oxygen isotopic composition of the quartz cement and modern formation water are approximately in equilibrium. These data for the Sihapas sandstone add to a growing body of evidence which indicates that cementation of sandstones can occur over geologically short periods of a few millions of years to a few tens of millions of years (Lee et al. 1985; Glassmann et al. 1989; Robinson and Gluyas 1992a).