Richard H. Worden

H2S-producing reactions in deep carbonate gas reservoirs: Khuff Formation, Abu Dhabi

Abstract The economic viability of gas production from deep reservoirs is often limited by the presence of hydrogen sulphide (H 2 S) thought to be the result of thermochemical sulphate reduction (TSR). This study constrains the reactions responsible for the origin of H 2 S-rich gas in a classic sour gas province: the Permian Khuff Formation of Abu Dhabi. In reservoirs hotter than 140°C, anhydrite has been partially replaced by calcite, and hydrocarbon gases have been partially or fully replaced by H 2 S. This shows that anhydrite and hydrocarbons have reacted together to produce calcite and H 2 S. Carbon and elemental sulphur isotope data from the gases and minerals show that the dominant reaction is: CaSO 4 + CH 4 → CaCO 3 + H 2 S + H 2 O Gas chemistry and isotope data also show that C 2+ gases reacted preferentially with anhydrite by reactions of the type: 2CaSO 4 + C 2 H 6 → 2CaCO 3 + H 2 S + S + 2H 2 O Sulphur was generated by this reaction and is locally present but was also consumed by the reaction: 4S + CH 4 +2H 2 O → CO 2 4H 2 S The frequently quoted and experimentally-observed reaction between anhydrite and H 2 S with CO 2 to produce calcite and sulphur: CaSO 4 + 3H 2 S + CO 2 → CaCO 3 + 4S + 3H 2 O has been shown to be insignificant in the Khuff Formation by gas chemistry, calcite δ 13 C and sulphur δ 34 S data. Direct reaction between methane and anhydrite occurred in solution, in residual pore waters which were initially dominated by dissolved carbonate derived from the marine dolomite matrix. The first-formed replacive calcite thus contains carbon derived principally from the marine dolomite matrix ( δ 13 C of about 0 to +4‰). Continuing reaction led to the progressive domination of the water by TSR-derived carbonate (minimum δ 13 C of about −31‰). Thermodynamic modelling using gas fugacity data was used to assess the controls on gas souring. To maintain equilibrium, anhydrite and methane should react together to produce calcite and H 2 S at all temperatures greater than 25°C. The coexistence of unreacted anhydrite and methane at shallow depths, in reservoirs cooler than 140°C, shows that thermodynamics alone do not control gas souring reactions. Rather, the coexistence of anhydrite and methane in shallow reservoirs and their reaction to produce H 2 S are kinetically controlled.

Geological storage of carbon dioxide

Abstract Carbon dioxide is the main compound identified as affecting the stability of the Earth’s climate. A significant reduction in the volume of greenhouse gas emissions to the atmosphere is a key mechanism for mitigating against climate change. Geological storage of CO2, or the injection and stabilization of large volumes of CO2 in the subsurface in saline aquifers, existing hydrocarbon reservoirs or unmineable coal-seams, is one of the more technologically advanced options available. A number of studies have been carried out aimed at understanding the behaviour and long term fate of CO2 when stored in geological formations.

Thermochemical sulphate reduction and the generation of hydrogen sulphide and thiols (mercaptans) in Triassic carbonate reservoirs from the Sichuan Basin, China

Abstract The Sichuan Basin in China is a sour petroleum province. In order to assess the origin of H2S and other sulphur compounds as well as the cause of petroleum alteration, data on H2S, thiophene and thiol concentrations and gas stable isotopes (δ34S and δ13C) have been collected for predominantly gas phase petroleum samples from Jurassic, Triassic, Permian and Upper Proterozoic (Sinian) reservoirs. The highest H2S concentrations (up to 32%) are found in Lower Triassic, anhydrite-rich carbonate reservoirs in the Wolonghe Field where the temperature has reached >130 °C. δ34S values of the H2S in the Wolonghe Triassic reservoirs range from +22 to +31‰ and are close to those of Triassic evaporitic sulphate from South China. All the evidence suggests that the H2S was generated by thermochemical sulphate reduction (TSR) locally within Triassic reservoirs. In the Triassic Wolonghe Field, both methane and ethane seem to be involved in thermochemical sulphate reduction since their δ13C values become less negative as TSR proceeds. Thiol concentrations correlate positively with H2S in the Triassic Wolonghe gas field, suggesting that thiol production is associated with TSR. In contrast, elevated thiophene concentrations are only found in Jurassic reservoirs in association with liquid phase petroleum generated from sulphur-poor source rocks. This may suggest that thiophene compounds have not come from a source rock or cracked petroleum. Rather they may have been generated by reaction between localized concentrations of H2S and liquid range petroleum compounds in the reservoir. However, in the basin, thiophene concentrations decrease with increasing vitrinite reflectance suggesting that source maturity (rather than source type) may also be a major control on thiophene concentration.

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.

Development of microporosity, diffusion channels and deuteric coarsening in perthitic alkali feldspars

Turbidity is an almost universal feature of alkali feldspars in plutonic rocks and has been investigated by us in alkali feldspars from the Klokken syenite using SEM and TEM. It is caused by the presence of myriads of tubular micro-inclusions, either fluid-filled micropores or sites of previous fluid inclusions, and is associated with coarsening of microperthite and development of sub-grains. Micropores are abundant in coarsened areas, in which porosities may reach 4.5%, but are almost absent from uncoarsened, pristine braind-microperthite areas. The coarsening is patchy, and involves a scale increase of up to 103 without change in the composition of the phases, low albite and low microcline, or in the bulk composition of the crystal. It occurs abruptly along an irregular front within individual crystals, which retain their original shapes. The coherent braid microperthite gives way across the front to an irregular semi-coherent film perthite over a few μm and then to a highly coarsened irregular patch perthite containing numerous small sub-grains on scales of a few hundred nm, in both phases. The coarsening and micropore formation occured at a T≤400°–450° C and it is inferred to have been driven by the release of coherent strain energy, low-angle grain-boundary migration being favoured by a fluid. The patchy nature of the coarsening and the absence of a relationship with initial grain boundaries suggest that the fluid was of local origin, possibly arising in part through exsolution of water from the feldspar. The sub-grain texture and microporosity modify profoundly the permeability of the rock, and greatly enhance the subsequent reactivity of the feldspars.

Thermochemical sulphate reduction in Cambro–Ordovician carbonates in Central Tarim

H2S and CO2 are found in elevated concentrations in Palaeozoic reservoirs in the Tarim Basin in China. We have carried out analyses on gas, petroleum, mineral cement and bulk rock compositions and isotope ratios together with petrography and fluid inclusion to assess the origin of the H2S. A deep crustal (e.g. volcanic) origin of the H2S and CO2 is unlikely since the inert gases, N2 and He, have isotope ratios totally uncharacteristic of this source. Organic sources are also unlikely since the source rock has low a sulphur content and the sulphur isotope ratio of the petroleum correlates positively with the sulphur content, the opposite of what would be anticipated from petroleum-derived H2S. Bacterial sulphate reduction is unlikely because temperatures are too high for bacteria to have survived. Thermochemical sulphate reduction of petroleum fluids by anhydrite in Lower Ordovician and Cambrian carbonate reservoirs is the most likely source of both the H2S and the CO2 causing isotopically characteristic pyrite, CO2 gas and calcite cement. H2S, and possibly CO2, migrated into Silurian sandstone reservoirs by cross formational flow. The H2S, with the same sulphur isotope ratio as Ordovician anhydrite, was partially lost from the fluid phase by extensive growth of late diagenetic pyrite. Similarly the CO2 was partially lost from the fluid phase by precipitation of late diagenetic calcite. The H2S that resulted from TSR underwent reaction with the remaining petroleum resulting in locally elevated organic sulphur concentrations in the petroleum and the progressive adoption of the Ordovician anhydrite sulphur isotope ratio.

The Influence of Rock Fabric and Mineralogy on Thermochemical Sulfate Reduction: Khuff Formation, Abu Dhabi

ABSTRACT Thermochemical sulfate reduction (TSR) is the reaction between anhydrite and petroleum fluids at elevated temperatures to produce H2S and calcite. In this study of the dolomite-hosted hydrocarbon gas reservoirs in the Permo-Triassic Khuff Formation, Abu Dhabi, a geochemically well constrained rock-gas system, we demonstrate for the first time a clear influence of rock texture and mineralogy on the rate and extent of TSR reactions and thus on H2S concentration in the gas phase. The controls on the rate on H2S accumulation were: TSR reaction kinetics. TSR became significant as temperature exceeded 140°C, a critical threshold temperature for chemical reaction between aqueous sulfate and aqueous methane. Anhydrite dissolution rate. Once initiated, the subsequent reaction rate was controlled by the rate of supply of aqueous sulfate to the reaction site. Sulfate limitation is indicated by the lack of fractionation of sulfur isotopes between sulfate and sulfide (i.e., suggesting total reaction for each unit of sulfate that dissolves). Also, finely crystalline anhydrite began reacting at a lower temperature than coarse crystalline anhydrite (likely a result of relative surface area), suggesting that anhydrite dissolution was the rate-limiting step. Transport rates are unlikely to have been rate-limiting at the earliest stage of reaction because anhydrite was replaced in situ by calcite on the very edges of anhydrite nodules and crystals. Transport rate. Later, as TSR proceeded, it became transport controlled, as calcite, growing on the surface of anhydrite crystals, began to isolate them from dissolved methane. TSR ceased once calcite had effectively armor-plated (totally isolated) the remaining anhydrite. Finely crystalline anhydrite underwent more extensive and more rapid TSR than coarser anhydrite crystals because these had a greater ratio of surface area to volume, allowing more and faster dissolution and requiring more calcite to isolate them from methane. Localized loss of H2S occurred in the reservoir by reaction with indigenous Fe-bearing clays. Consequently, reservoirs with a relatively high siliciclastic content have less H2S than would be expected from the advanced state of anhydrite replacement by calcite. In order to predict TSR-related H2S concentration in hydrocarbon gases it is thus important to understand the diagenetic and textural characteristics of the reservoir as well as the thermal and petroleum-emplacement history.

The long-term fate of CO2 in the subsurface: natural analogues for CO2 storage

Abstract CO2 is a common gas in geological systems so that planned storage of CO2 in the subsurface may do no more than mimic nature. Natural CO2 has a wide number of sources that can be at least partly identified by carbon stable isotope geochemistry. Three pairs of case studies with different reservoir characteristics and CO2 contents have been examined to assess the natural impact of adding CO2 to geological systems. Carbonate minerals partially dissolve when CO2 is added simply because the CO2 dissolves in water and forms an acidic solution. Therefore, carbonate minerals in the subsurface are not capable of sequestering secondary CO2. The addition of CO2 to a pure quartz sandstone (or a sandstone in which the supply of reactive aluminosilicate minerals has been exhausted by excess natural CO2 addition) will have no consequences: the CO2 will simply saturate the water and then build up as a separate gas phase. The addition of CO2 to carbonate cemented sandstone without reactive aluminosilicate minerals will induce a degree of carbonate mineral dissolution but no solid phase sequestration of the added CO2. When CO2 is naturally added to sandstones it will induce combined aluminosilicate dissolution and carbonate cementation if the aluminosilicate minerals contain calcium or magnesium (or possibly iron). Examination of a CO2-filled porous sandstone with abundant reactive aluminosilicate minerals that received a huge CO2 charge about 8000 to 100 000 years ago reveals minimal evidence of solid phase sequestration of the added CO2. This indicates that either dissolution of reactive aluminosilicates or precipitation of carbonate minerals is relatively slow. It is very likely that the slow dissolution of reactive aluminosilicates is the rate-limiting step. Solid phase sequestration of CO2 occurs only when reactive aluminosilicates are present in a rock and when the system has had many tens to hundreds of thousands of years to equilibrate. The two critical aspects of the behaviour of CO2 when injected into the subsurface are (1) that the rock must contain reactive Ca and Mg aluminosilicates and (2) that reaction to produce carbonate minerals is extremely slow on a human timescale. The reactive minerals include anorthite, zeolite, smectite and other Fe- and Mg-clay minerals. Such minerals are absent from clean sandstones and limestones but are present in ‘dirty’ standstones (lithic arenites which are mineralogically immature) and some mudstones. The analysis of geological analogues shows that injection of CO2 into carbonate-bearing rocks that do not contain reactive minerals will induce dissolution of the carbonate, whether it is a matrix cement, rock fragment, fault seal or part of a top-sealing mudstone.

Geochemical evolution of a palaeolaterite: the Interbasaltic Formation, Northern Ireland

Abstract The Interbasaltic laterites of Northern Ireland were formed during a period of relative volcanic inactivity by extensive chemical weathering of Tertiary basalts. They reach a maximum thickness of 30 m and once provided a major source of iron and aluminium ore. An extensive database comprising major, minor, and trace elements has been compiled for 240 samples in order to study the effects of weathering in terms of the changes in whole-rock chemistry and mineralogy from basalt through to iron-rich crust. Percolating waters caused degradation of the parent basalt mineralogy and precipitation of neoformed phases, principally through incongruent dissolution processes. Primary olivine, plagioclase feldspar, and augite were successively broken down and replaced by a mineral assemblage consisting of hematite, gibbsite, goethite, anatase, meta-halloysite and kaolinite. Changes in mineralogy facilitated concomitant changes in element concentrations. Mass balance calculations indicate that all elements were depleted in the iron crust. Enrichment of Al, LOI, Cr, Cu, and V occurred in the laterite horizon, while enrichment of Al, LOI, Ba, Ce, Cr, Cu, Ni, and Rb occurred in the lithomarge. Notably, yttrium was found to be mobile indicating that weathered basalts should not be used in discrimination of original tectonic environments. The severe leaching conditions evidenced by yttrium depletion, local aluminium redistribution, and iron crust formation are indicative of weathering under a humid sub-tropical monsoon climate.

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.