Norman H. Oxtoby

Gas Souring by Thermochemical Sulfate Reduction at 140¡C: Reply

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temperature: 140°C. Petrographic examination of core from a wide depth range showed that the anhydrite reactant has been replaced by calcite reaction product only in samples deeper than 4300 m. Gas composition data show that only reservoirs deeper than 4300 m contain large quantities of H2S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.

The effects of thermochemical sulfate reduction upon formation water salinity and oxygen isotopes in carbonate gas reservoirs

Abstract 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 relationship between petroleum emplacement and carbonate reservoir quality: examples from Abu Dhabi and the Amu Darya Basin

Abstract 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.

Feldspar dissolution, authigenic clays, and quartz cements in open and closed sandstone geochemical systems during diagenesis: Typical examples from two sags in Bohai Bay Basin, East China

Feldspar dissolution and precipitation of clays and quartz cements are important diagenetic reactions affecting reservoir quality evolution in sandstones with detrital feldspars. We examined two sets of sandstone reservoirs to determine whether the sandstone diagenetic systems were open or closed to the mass transfer of products from feldspar dissolution and its impact on reservoir quality. One of the reservoirs is the Eocene fan delta sandstone buried 2.5–4.0 km (1.5–2.5 mi) below sea level (BSL) in the Gaoliu (GL) area of the Nanpu sag, and the other is the Eocene subaqueous fan sandstone buried 1.5–4.5 km (1–2.8 mi) BSL in the Shengtuo (ST) area of the Dongying sag. Both sandstones consist mainly of lithic arkoses and feldspathic litharenites, and have secondary porosity formed by dissolution of feldspars. In the GL sandstones, the absolute amounts of authigenic clays and quartz cements (generally 125°C [257°F]). The low abundance of authigenic clays and quartz cements, and low pore-water salinity indicate that much of the , , and released from leached K-feldspars were exported from the GL sandstone system. And the extensive feldspar dissolution enhanced much porosity and permeability. In contrast, the ST sandstones with secondary pores formed by feldspar dissolution generally contain authigenic clays (kaolinite and illite) and quartz cements with almost identical volume of secondary pores. Kaolinite dominates in the ST sandstones at shallower depth (3.1 km [2 mi] BSL) where temperature exceeds 125°C (257°F). The presence of abundant clays and quartz cements indicates that and released from leached feldspars were retained in the ST sandstone system. The dominance of authigenic illite at greater depth indicates that sufficient should have been retained within the sandstones for occurrence of illitization of kaolinite and feldspars. Secondary porosity in thin sections can be up to 3%, but little porosity ( The diagenetic difference between the GL and the ST sandstones can be interpreted by assessing pore-water evolution in these two areas. The current pore waters with low salinity and negative hydrogen isotopic compositions in the GL sandstone system indicate the significant impact of meteoric water, whereas the current pore waters with high salinity and the paleofluids with positive oxygen isotopic compositions in the ST sandstone system indicate little trace of meteoric water. Access of meteoric freshwater to the GL area probably occurred during the late Oligocene to Neogene through widely developed faults in the Paleogene and Neogene strata. The low-salinity water could have been responsible for flushing of solutes derived from feldspar dissolution. As such, diagenesis in the GL sandstones is considered to have occurred in an open geochemical system, whereas with limited faults and high water salinity, the ST sandstones acted as a closed geochemical system where precipitation of kaolinite, illite, and quartz cements occurred following dissolution of feldspars.

Evidence against natural deformation of fluid inclusions in diagenetic quartz

Abstract 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.