Search

Exotic minerals, i.e. those that do not have an obvious source of components within the host rocks, can be major porosity occluding cement and replacement phases in subsurface carbonate reservoirs. Here we present and discuss petrographic and fluid inclusion data from a number of petroleum systems. These have had different geological histories but a common factor is the presence of exotic mineral cements and late stage dissolution. The effect of these cements and late stage dissolution on reservoir quality is also considered. Petroleum filling does not appear to inhibit the precipitation of exotic cements in the way that it appears to inhibit the precipitation of calcite. Burial dolomite and anhydrite are the most important of these volumetrically but they are often accompanied by other late stage cements such as fluorite, kaolin, quartz, barite, celestite, sphalerite and galena, generally in much smaller quantities. In accounting for the concentration of the material contained in these cements compared with the host rocks, stylolitisation is a possible mechanism in some cases, but, in many others, import from sources external to the reservoir is required.

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

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.

Thermochemical sulfate reduction (TSR) is a well known process that can lead to sour (H2S-rich) petroleum accumulations. Most studies of TSR have concentrated upon gas chemistry. In this study we have investigated palaeoformation water characteristics in a deep, anhydrite-bearing dolomite, sour-gas reservoir of Permian age in Abu Dhabi using fluid inclusion, stable isotope, petrographic, and gas chemical data. The data show that low salinity, isotopically-distinct water was generated within the reservoir by reaction between anhydrite and methane. The amount of water added to the reservoir from TSR, indicated by reduced fluid inclusion salinity and water δ18O values, varied systematically with the extent of anhydrite reaction with methane. Water salinity and isotope data show that the original formation water was diluted by between four and five times by water from TSR. Thus, we have shown that large volumes of very low salinity water were generated within the gas reservoirs during diagenesis following gas emplacement. The salinity of formation water in evaporite lithologies is, therefore, not necessarily high. Modelling, based upon a typical Khuff gas reservoir rock volume, suggests that initial formation water volumes can only be increased by about three times as a result of TSR. The extreme local dilution shown by the water salinity and δ18O data must, therefore, reflect transiently imperfect mixing between TSR water and original formation water. The creation of large volumes of water has important implications for the mechanism and rate of thermochemical sulphate reduction and the interpretation of gas volumes using petrophysical logging tools.

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.

This paper describes evidence for and against burial induced deformation of fluid inclusions in diagenetic quartz. Fluid inclusions in diagenetic minerals are prone to non-elastic deformation (stretching or leakage) if subjected to progressive burial in a sedimentary basin. If they deform, they cannot record mineral growth conditions correctly. A correlation between homogenization temperature and depth may be interpreted as indicating wholesale leakage or stretching. Experimental work and theoretical studies suggest that heating >200°C higher than the homogenization temperature is required to produce significant deformation, but it may not be possible to extend the results to natural conditions. The experiments further predict a correlation between homogenization temperature and inclusion size in a sample of inclusions that have undergone natural deformation. This is not observed in natural examples, but the absence of a correlation is not proof that leakage has not occurred. Several features of inclusion data in quartz cements do, however, argue against stretching or leakage. Homogenization temperatures commonly show narrow distributions and are compatible with independent data such as illite potassium-argon ages and petrography. Different generations of inclusions in a single sample set also retain homogenization temperature distributions compatible with their sequential origin. Taken as a whole, the body of evidence argues against widespread stretching or leakage of fluid inclusions in diagenetic quartz.

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.

Natural gas in the Permian-Triassic Khuff Formation of Abu Dhabi contains variable amounts of H2S. Gas souring occurred through thermochemical sulfate reduction of anhydrite by hydrocarbon gases. Sour gas is observed only in reservoirs hotter than a critical reaction temperature: 140°C. Petrographic examination of core from a wide depth range showed that the anhydrite reactant has been replaced by calcite reaction product only in samples deeper than 4300 m. Gas composition data show that only reservoirs deeper than 4300 m contain large quantities of H2S (i.e., >10%). At present-day geothermal gradients, 4300 m is equivalent to 140°C. Fluid inclusion analysis of calcite reaction product has shown that calcite growth only became significan at temperatures greater than 140°C. Thus, three independent indicators all show that 140°C is the critical temperature above which gas souring by thermochemical sulfate reduction begins. The previously suggested lower temperature thresholds for other sour gas provinces (80-130°C) derive from gas composition data that may not allow adequately either for the reservoir temperature history or for the migration of gas generated at higher temperatures into present traps. Conversely, published proposals for higher threshold temperature (180-200°C) derive from short duration experimental data that are not easily extrapolated to geologically realistic temperatures and time scales. Therefore, the temperature of 140°C derived from our study of the Khuff Formation may be th best estimate of temperature required for in-situ thermochemical sulfate reduction to produce the high H2S concentrations encountered in deep carbonate gas reservoirs.