Mitigation of asphaltics deposition during CO2 flood by enhancing CO2 solvency with chemical modifiers

CO₂ injected in the reservoir of McElroy Field, TX, for a CO₂ flood was in the supercritical state. Supercritical CO₂ fluid is capable of extracting light and intermediate hydrocarbons from rocks but is unable to extract heavy hydrocarbons and asphaltics. Therefore, plugging of asphaltics in reservoir rocks and a consequent reduction in injectivity and recovery may result when CO₂ only is used in enhanced oil recovery. By adding common solvents as chemical modifiers, the flooding fluid shows marked improvement in solvency for heavy components of crudes due to its increased density and polarity. Numerous supercritical CO₂ fluid extractions of dolomite rock from the Grayburg Formation containing known amount of spiked McElroy crude oil have been carried out to evaluate extraction efficiencies of CO₂ and CO₂ with chemical modifiers at various temperatures and pressures. All experiments show that extraction efficiency increases with increasing CO₂ pressure but decreases with increasing temperature. Addition of chemical modifiers to CO₂ also shows improved extraction efficiency and reduced asphaltic deposits. Under the pressure and temperature similar to McElroy reservoir conditions; chemically modified CO₂ yielded almost 3 times as much oil extracts as those in extractions with CO₂ only. It also reduced the asphaltics content in extracted rocks to nearly one half; indicating its potential for mitigating asphaltics plugging of formation rocks     

Effects of Deep Fluids on Hydrocarbon Generation and Accumulation in Chinese Petroliferous Basins

Deep fluids in a petroliferous basin generally come from the deep crust or mantle beneath the basin basement, and they transport deep substances(gases and aqueous solutions) as well as heat to sedimentary strata through deep faults. These deep fluids not only lead to large-scale accumulations of CO_2, CH_4, H_2, He and other gases, but also significantly impact hydrocarbon generation and accumulation through organic-inorganic interactions. With the development of deep faults and magmatic-volcanic activities in different periods, most Chinese petroliferous basins have experienced strong impacts associated with deep fluid activity. In the Songliao, Bohai Bay, Northern Jiangsu, Sanshui, Yinggehai and Pearl Mouth Basins in China, a series of CO_2 reservoirs have been discovered. The CO_2 content is up to 99%, with δ~(13)C_(CO2) values ranging from-4.1‰ to-0.37‰ and ~3He/~4He ratios of up to 5.5 Ra. The abiogenic hydrocarbon gas reservoirs with commercial reserves, such as the Changde, Wanjinta, Zhaozhou, and Chaoyanggou reservoirs, are mainly distributed in the Xujiaweizi faulted depression of the Songliao Basin. The δ~(13)CCH4 values of the abiogenic alkane gases are generally -30‰ and exhibit an inverse carbon isotope sequence of δ~(13)C_(CH4)δ~(13)C_(C2H6)δ~(13)C_(C3H8)δ~(13)C_(C4H10). According to laboratory experiments, introducing external H_2 can improve the rate of hydrocarbon generation by up to 147% through the kerogen hydrogenation process. During the migration from deep to shallow depth, CO_2 can significantly alter reservoir rocks. In clastic reservoirs, feldspar is easily altered by CO_2-rich fluids, leading to the formation of dawsonite, a typical mineral in high CO_2 partial pressure environments, as well as the creation of secondary porosity. In carbonate reservoirs, CO_2-rich fluids predominately cause dissolution or precipitation of carbonate minerals. The minerals, e.g., calcite and dolomite, show some typical features, such as higher homogenization temperatures than the burial temperature, relatively high concentrations of Fe and Mn, positive Eu anomalies, depletion of 18 O and enrichment of radiogenic ~(87)Sr. Due to CO_2-rich fluids, the development of high-quality carbonate reservoirs is extended to deep strata. For example, the Well TS1 in the northern Tarim Basin revealed a high-quality Cambrian dolomite reservoir with a porosity of 9.1% at 8408 m, and the Well ZS1 C in the central Tarim Basin revealed a large petroleum reserve in a Cambrian dolomite reservoir at ~6900 m. During the upward migration from deep to shallow basin strata, large volumes of supercritical CO_2 may extract petroleum components from hydrocarbon source rocks or deep reservoirs and facilitate their migration to shallow reservoirs, where the petroleum accumulates with the CO_2. Many reservoirs containing both supercritical CO_2 and petroleum have been discovered in the Songliao, Bohaiwan, Northern Jiangsu, Pearl River Mouth and Yinggehai Basins. The components of the petroleum trapped with CO_2 are dominated by low molecular weight saturated hydrocarbons.     

Origin of Crude Oil in the Lunnan Region,Tarim Basin

<正>The oil source of the Tarim Basin has been controversial over a long time.This study characterizes the crude oil and investigates the oil sources in the Lunnan region,Tarim Basin by adopting compound specific isotopes of n-alkanes and biomarkers approaches.Although the crude oil has a good correlation with the Middle-Upper Ordovician(O_(2+3)) source rocks and a poor correlation with the Cambrian-Lower Ordovician((?)-O_1) based on biomarkers,theδ~(13)C data of n-alkanes of the Lunnan oils show an intermediate value between(?)-O_1 and O_(2+3) genetic affinity oils,which suggests that the Lunnan oils are actually of an extensively mixed source.A quantification of oil mixing was performed and the results show that the contribution of the Cambrian-Lower Ordovician source rocks ranges from 11%to 70%(averaging 36%),slightly less than that of the Tazhong uplift.It is suggested that the inconsistency between the biomarkers andδ~(13)C in determining the oil sources in the Lunnan Region results from multiple petroleum charge episodes with different chemical components in one or more episode(s) and different sources.The widespread marine mixed-source oil in the basin indicates that significant petroleum potential in deep horizons is possible.To unravel hydrocarbons accumulation mechanisms for the Lunnan oils is crucial to further petroleum exploration and exploitation in the region.     

A chemical and thermodynamic model of oil generation in hydrocarbon source rocks

Thermodynamic calculations and Gibbs free energy minimization computer experiments strongly support the hypothesis that kerogen maturation and oil generation are inevitable consequences of oxidation/reduction disproportionation reactions caused by prograde metamorphism of hydrocarbon source rocks with increasing depth of burial.These experiments indicate that oxygen and hydrogen are conserved in the process.Accordingly, if water is stable and present in the source rock at temperatures ?25 but ?100 °C along a typical US Gulf Coast geotherm, immature (reduced) kerogen with a given atomic hydrogen to carbon ratio (H/C) melts incongruently with increasing temperature and depth of burial to produce a metastable equilibrium phase assemblage consisting of naphthenic/biomarker-rich crude oil, a type-II/III kerogen with an atomic hydrogen/carbon ratio (H/C) of ∼1, and water. Hence, this incongruent melting process promotes diagenetic reaction of detritus in the source rock to form authigenic mineral assemblages.However, in the water-absent region of the system CHO (which is extensive), any water initially present or subsequently entering the source rock is consumed by reaction with the most mature kerogen with the lowest H/C it encounters to form CO₂ gas and a new kerogen with higher H/C and O/C, both of which are in metastable equilibrium with one another.This hydrolytic disproportionation process progressively increases both the concentration of the solute in the aqueous phase, and the oil generation potential of the source rock; i.e., the new kerogen can then produce more crude oil.Petroleum is generated with increasing temperature and depth of burial of hydrocarbon source rocks in which water is not stable in the system CHO by a series of irreversible disproportionation reactions in which kerogens with higher (H/C)s melt incongruently to produce metastable equilibrium assemblages consisting of crude oil, CO₂ gas, and a more mature (oxidized) kerogen with a lower H/C which in turn melts incongruently with further burial to produce more crude oil, CO₂ gas, and a kerogen with a lower H/C and so forth.The petroleum generated in the process progresses from heavy naphthenic crude oils at low temperatures to mature petroleum at ∼150 °C. For example, the results of Computer Experiment 27 (see below) indicate that the overall incongruent melting reaction in the water-absent region of the system C-H-O at 150 °C and a depth of ∼4.3 km of an immature type-II/III kerogen with a bulk composition represented by C₂₉₂H₂₈₈O_12(c) to produce a mature (oxidized) kerogen represented by C₁₂₈H₆₈O_7(c), together with a typical crude oil with an average metastable equilibrium composition corresponding to C_8.8H_16.9 (C_8.8H_16.9(l)) and CO₂ gas (CO_2(g)) can be described by writing

(A)     

Geochemical evaluation of Niger Delta sedimentary organic rocks: a new insight

A geochemical evaluation of Niger Delta organic matter was carried out using supercritical fluid extraction (SFE) sample preparation procedure. Comparison of geochemical significance of gas chromatographic data of rock extracts of SFE with those of Soxhlet extraction method from previous studies was made in order to establish the usefulness of SFE in geochemical exploration. The assessment of geochemical character of the rock samples from the comparison and interpretation of other geochemical parameters were used to give more insights into understanding the source rocks characteristics of onshore and shelf portions of the Niger Delta Basin. The results of the gas chromatographic (GC) analysis of the rock extracts across the lithostratigraphic units show that Pr/Ph, Pr/nC₁₇, Pr/nC₁₈, CPI and odd/even preference ranged from 0.07 to 12.39, 0.04 to 6.66, 0.05 to 13.80, 0.12 to 8.4 and 0.06 to 8.12, respectively. The Rock-Eval pyrolysis data and geochemical ratios and parameters calculated from the GC data showed that most of the samples are mature and have strong terrestrial provenance while a few samples have strong marine provenance. The few marine source rocks are located in the deeper depth horizon. Pr/Ph and standard geochemical plots indicate that most of samples were derived from organic matter deposited in less reducing conditions, i.e. more of oxidizing conditions while a few samples have predominantly influence of reducing conditions. The results of trace metal analysis of older samples from Agbada Formation also indicate marine and mixed organic matter input deposited in less reducing conditions. The results obtained in this study are comparable with those obtained from previous studies when Soxhlet extraction method was used and also indicated the presence of more than one petroleum systems in the Niger Delta.     

Interactions between basalts and oil source rocks in rift basins： CO2 generation

Basalts interbedded with oil source rocks are discovered frequently in rift basins of eastern China, where CO2 is found in reservoirs around or within basalts, for example in the Binnan reservoir of the Dongying Depression. In the reservoirs, CO2 with heavy carbon isotopic composition (δ13C>-10‰ PDB) is in most cases accounts for 40% of the total gas reserve, and is believed to have resulted from degassing of basaltic magma from the mantle. In their investigations of the Binnan reservoir, the authors suggested that the CO2 would result from interactions between the source rocks and basalts. As the source rocks around basalts are rich in carbonate minerals, volcanic minerals, transition metals and organic matter, during their burial history some of the transition metals were catalyzed on the thermal degradation of organic matter into hydrocarbons and on the decomposition of carbonate minerals into CO2, which was reproduced in thermal simulations of the source rocks with the transition metals (Ni and Co). This kind of CO2 accounts for 55%-85% of the total gas reserve generated in the process of thermal simulation, and its δ13C values range from -11‰- -7.2‰ PDB, which are very similar to those of CO2 found in the Binnan reservoir. The co-generation of CO2 and hydrocarbon gases makes it possible their accumulation together in one trap. In other words, if the CO2 resulted directly from degassing of basaltic magma or was derived from the mantle, it could not be accumulated with hydrocarbon gases because it came into the basin much earlier than hydrocarbon generation and much earlier than trap formation. Therefore, the source rocks around basalts generated hydrocarbons and CO2 simultaneously through catalysis of Co and Ni transition metals, which is useful for the explanation of co-accumulation of hydrocarbon gases and CO2 in rift basins in eastern China.     

CS2/NMP extraction of immature source rock concentrates

Eleven Chinese immature source rock concentrates from the immature oil formations in four different depressions were extracted ultrasonically with a mixture of CS₂ and N-methyl-2-pyrrolidinone (CS₂/NMP) at room temperature. The samples were also extracted with CHCl₃ and a mixture of methanol/acetone/chloroform (MAC) for comparison. The solvent system CS₂/NMP is very efficient for the extraction of immature source rock concentrates, giving much higher extraction yields than CHCl₃ or MAC. The composition of the extracts using different solvent mixtures is also different. Model compound tests indicate that no chemical reactions have taken place between the NMP and the substrates in the extraction. These results suggest that there are abundant non-covalent bond interactions in the organic matter of the immature source rock concentrates. The fact that CS₂/NMP mixed solvent extracts more than MAC and CHCl₃ is not only because it can dissolve higher molecular weight fractions, but also because it has stronger ability to disrupt the complex interactions existing between the soluble and insoluble fractions. Biomarker distributions in the saturated hydrocarbon fractions are different for different solvent systems, suggesting that care should be taken when comparing the biomarker parameters in source rocks when using different solvents for extraction.     

Metamorphic CO2 production from calc-silicate rocks via garnet-forming reactions in the CFAS–H2O–CO2 system

The type and kinetics of metamorphic CO₂-producing processes in metacarbonate rocks is of importance to understand the nature and magnitude of orogenic CO₂ cycle. This paper focuses on CO₂ production by garnet-forming reactions occurring in calc-silicate rocks. Phase equilibria in the CaO–FeO–Al₂O₃–SiO₂–CO₂–H₂O (CFAS–CO₂–H₂O) system are investigated using P–T phase diagrams at fixed fluid composition, isobaric T–X(CO₂) phase diagram sections and phase diagram projections in which fluid composition is unconstrained. The relevance of the CFAS–CO₂–H₂O garnet-bearing equilibria during metamorphic evolution of calc-silicate rocks is discussed in the light of the observed microstructures and measured mineral compositions in two representative samples of calc-silicate rocks from eastern Nepal Himalaya. The results of this study demonstrate that calc-silicate rocks may act as a significant CO₂ source during prograde heating and/or early decompression. However, if the system remains closed, fluid–rock interactions may induce hydration of the calc-silicate assemblages and the in situ precipitation of graphite. The interplay between these two contrasting processes (production of CO₂-rich fluids vs. carbon sequestration through graphite precipitation) must be considered when dealing with a global estimate of the role exerted by decarbonation processes on the orogenic CO₂ cycle.     

Numerical analysis of the effect of natural microcracks on the supercritical CO2 fracturing crack network of shale rock based on bonded particle models

The problem of predicting the geometric structure of induced fractures is highly complex and significant in the fracturing stimulation of rock reservoirs. In the traditional continuous fracturing models, the mechanical properties of reservoir rock are input as macroscopic quantities. These models neglect the microcracks and discontinuous characteristics of rock, which are important factors influencing the geometric structure of the induced fractures. In this paper, we simulate supercritical CO₂ fracturing based on the bonded particle model to investigate the effect of original natural microcracks on the induced‐fracture network distribution. The microcracks are simulated explicitly as broken bonds that form and coalesce into macroscopic fractures in the supercritical CO₂ fracturing process. A calculation method for the distribution uniformity index (DUI) is proposed. The influence of the total number and DUI of initial microcracks on the mechanical properties of the rock sample is studied. The DUI of the induced fractures of supercritical CO₂ fracturing and hydraulic fracturing for different DUIs of initial microcracks are compared, holding other conditions constant. The sensitivity of the DUI of the induced fractures to that of initial natural microcracks under different horizontal stress ratios is also probed. The numerical results indicate that the distribution of induced fractures of supercritical CO₂ fracturing is more uniform than that of common hydraulic fracturing when the horizontal stress ratio is small.     

Petrophysical characterization of the South Georgia Rift Basin for supercritical CO2 storage: a preliminary assessment

The Triassic–Jurassic South Georgia Rift (SGR) Basin, buried beneath Coastal Plain sediments of southern South Carolina, southeastern Georgia, western Florida, and southern Alabama, consists of an assemblage of continental rift deposits (popularly called red beds), and mafic igneous rocks (basalt flows and diabase sills). The red beds are capped by basalts and/or diabase sills, and constitute the target for supercritical CO₂ storage as part of a Department of Energy funded project to study the feasibility for safe and permanent sequestration. The purpose of this research is to evaluate subsurface suitability for underground CO₂ storage in terms of the local and regional distribution of porous and permeable reservoirs. In addition, unlike shale-capped CO₂ reservoirs, very little is known about the ability of basalts and diabase sills to act as viable seals for CO₂ storage. New results demonstrate the presence of confined porous rocks that may be capable of storing significant quantities of supercritical CO₂. Reservoir thicknesses as high as 420 m and an average porosity as high as 14 % were obtained. The SGR Basin manifests distinct porosity–permeability regimes that are influenced by the depositional environments. These are: a high-porosity, medium/low-permeability zone associated with lacustrine deposits, a medium/low-porosity, low-permeability zone dominated by fluvial fine- to very fine-grained sandstone, and an extremely low porosity and permeability zone characterized by fluvial and alluvial-fan deposits. Analyses further show that the basalt flows and diabase sills are characterized by low porosity as well as high seismic velocities and densities that are favorable to caprock integrity.     

The origin and significance of non-aqueous CO2 fluid inclusions in the auriferous veins of Bin Yauri,northwestern Nigeria

Non-aqueous CO₂ and CO₂-rich fluid inclusions are found in the vein quartz hosting mesothermal gold-sulphide mineralization at Bin Yauri, northwestern Nigeria. Although mineralizing fluids responsible for gold mineralization are thought to be CO₂-rich, the occurrence of predominantly pure to nearly pure CO₂ inclusions is nevertheless unusual for a hydrothermal fluid system. Many studies of similar CO₂-rich fluid inclusions, mainly in metamorphic rocks, proposed preferential loss (leakage) of H₂O from H₂O-CO₂ inclusions after entrapment. In this study however, it is proposed that phase separation (fluid immiscibility) of low salinity CO₂-rich hydrothermal fluids during deposition of the gold mineralization led to the loss of the H₂O phase and selective entrapment of the CO₂. The loss of H₂O to the wallrocks resulted in increasing oxidizing effects. There is evidence to suggest that the original CO₂-rich fluid was intrinsically oxidized, or perhaps in equilibrium with oxidizing conditions in the source rocks. The source of the implicated fluid is thought to be subducted metasediments, subjected to dehydration and devolatilization reactions along a transcurrent Anka fault/shear system, which has been described as a Pan-African (450–750 Ma) crustal suture.     

Thermal simulation of basic volcanic fluid influence on different source rocks

Based on thermal simulation experiment, interactions between volcanic fluids and source rocks were studied. Gas generations in the dry system and fluid system under different temperatures were analyzed. The results showed that the various types of source rocks are similar in composition, containing gaseous C1-C5 hydrocarbons, H2 and CO2 whose gas yields increase with increasing temperature. The gas yield of source rocks of type I is the high- est, followed by type II, and that of source rocks of type III is the lowest, indicating that the yield of hydrocarbon gases is related to their hydrocarbon generating potential. Although the generating potential of type III is the lowest, it can still be regarded as a useful gas source when it is buried deeply enough. The basic volcanic fluid restrains the generation of gaseous hydrocarbons in different types of source rocks, but promotes the generation of inorganic gases.     

Insight into interactions of olivine-scCO2-water system at 140 °C and 15 MPa during CO2 mineral sequestration

CO₂ mineral sequestration (in ultrabasic or basaltic rocks) has been considered as a promising long-term and stable approach to reduce CO₂ in the atmosphere and would counteract the effect of global warming. Meanwhile, clays are widely found in ultrabasic reservoirs. In our study, clays were observed in natural olivine samples, which were used for laboratory experiments in a supercritical CO₂ system at 140 °C and 15 MPa. Initial olivine samples were crushed into two sizes which were large grains of ∼850–1000 μm and powder particles of ∼75–150 μm, with the durations of 400 and 1000 h for the powder and grains, respectively. The results showed amorphous silica was newly formed and this passivating layer could mitigate the water-rock interaction to some extent, but it would not play a long-term prohibited effect on secondary mineral carbonate formation as it is a Fe(III) free silica coating. More interestingly, the secondary carbonates were observed to form near the surface sites where locates more clays. Our findings provide insights into the reaction mechanisms of olivine-scCO₂-water interaction process in natural ultrabasic rocks.     

Experimental study of potential wellbore cement carbonation by various phases of carbon dioxide during geologic carbon sequestration

Hydrated Portland cement was reacted with CO₂ in supercritical, gaseous and aqueous phases to understand the potential cement alteration processes along the length of a wellbore, extending from a deep CO₂ storage reservoir to the shallow subsurface during geologic carbon sequestration. The 3-D X-ray microtomography (XMT) images showed that the cement alteration was significantly more extensive with CO₂-saturated synthetic groundwater than dry or wet supercritical CO₂ at high P (10 MPa)-T (50 °C) conditions. Scanning electron microscopy with energy dispersive spectroscopy (SEM–EDS) analysis also exhibited a systematic Ca depletion and C enrichment in cement matrix exposed to CO₂-saturated groundwater. Integrated XMT, XRD and SEM–EDS analyses identified the formation of an extensive carbonated zone filled with CaCO₃(s), as well as a porous degradation front and an outermost silica-rich zone in cement after exposure to CO₂-saturated groundwater. Cement alteration by CO₂-saturated groundwater for 2–8 months overall decreased the porosity from 31% to 22% and the permeability by an order of magnitude. Cement alteration by dry or wet supercritical CO₂ was slow and minor compared to CO₂-saturated groundwater. A thin single carbonation zone was formed in cement after exposure to wet supercritical CO₂ for 8 months or dry supercritical CO₂ for 15 months. An extensive calcite coating was formed on the outside surface of a cement sample after exposure to wet gaseous CO₂ for 1–3 months. The chemical–physical characterization of hydrated Portland cement after exposure to various phases of CO₂ indicates that the extent of cement carbonation can be significantly heterogeneous depending on the CO₂ phase present in the wellbore environment. Both experimental and geochemical modeling results suggest that wellbore cement exposure to supercritical, gaseous and aqueous phases of CO₂ during geologic C sequestration is unlikely to damage the wellbore integrity because cement alteration by all phases of CO₂ is dominated by carbonation reactions. This is consistent with previous field studies of wellbore cement with extensive carbonation after exposure to CO₂ for three decades. However, XMT imaging indicates that preferential cement alteration by supercritical CO₂ or CO₂-saturated groundwater can occur along the cement–steel or cement–rock interfaces. This highlights the importance of further investigation of cement degradation along the interfaces of wellbore materials to ensure permanent geologic carbon storage.     

Secondary siderite-oxide-sulphide and carbonate-andalusite assemblages in cordierite granulites from Sri Lanka: post-granulite facies fluid evolution during uplift

We report here that some of the pelitic rocks from the Wanni and Highland Complexes of Sri Lanka reacted with CO₂-rich fluids to produce a wide range of unusual secondary carbonate-silicate-oxide-sulphide assemblages. These enable the depth, temperature and fluid compositions of CO₂ reactions to be calculated more rigorously than is generally possible for the patches of arrested charnockite that have been described from Sri Lanka. Magnesite-andalusite-quartz has partially replaced primary cordierite, and siderite-rutile replaced ilmenite. Paragenetic sequences involving primary pyrrhotite, ilmenite and magnetite and secondary pyrite-siderite-rutile-magnetite-(hematite) demonstrate the control which carbonate equilibria have upon evolving fluid compositions during cooling. Direct evidence for the role of graphite as a source of CO₂ is found in the Highland Complex where primary graphite partially reacted with silicates to form secondary siderite assemblages. It is proposed that following peak metamorphism, continued uplift along a clockwise P-T-t path was accompanied by a series of devolatilization reactions involving breakdown of graphite and the continuous production of secondary CO₂-rich fluids. The limited extent of disseminated secondary carbonate reflects the small amount of graphite inferred to have been present in the source rocks. These rocks demonstrate that CO₂-rich fluids, as found in disseminated fluid inclusions, need not form during peak granulite metamorphism but may be an inevitable consequence of continued uplift along a clockwise P-T-t path. The arrested charnockite which overprinted some of the hornblende-bearing felsic-intermediate composition rocks in Sri Lanka most likely formed by the same process. Received: 4 May 1994 / Accepted: 25 October 1996     

The nature of fluids during pegmatite development in metamorphic terrains: Evidence from Hamadan complex,Sanandaj-Sirjan metamorphic zone,Iran

In the Sanandaj-Sirjan zone of metamorphic belt of Iran, the area south of Hamadan city comprises of metamorphic rocks, granitic batholith with pegmatites and quartz veins. Alvand batholith is emplaced into metasediments of early Mesozoic age. Fluid inclusions have been studied using microthermometry to evaluate the source of fluids from which quartz veins and pegmatites formed to investigate the possible relation between host rocks of pegmatites and the fluid inclusion types. Host minerals of fluid inclusions in pegmatites are quartz, andalusite and tourmaline. Fluid inclusions can be classified into four types. Type 1 inclusions are high salinity aqueous fluids (NaCl_eq >12 wt%). Type 2 inclusions are low to moderate salinity (NaCl_eq <12 wt%) aqueous fluids. Type 3 and 4 inclusions are carbonic and mixed CO₂-H₂O fluid inclusions. The distribution of fluid inclusions indicate that type 1 and type 2 inclusions are present in the pegmatites and quartz veins respectively in the Alvand batholith. This would imply that aqueous magmatic fluids with no detectable CO₂ were present during the crystallization of these pegmatites and quartz veins. Types 3 and 4 inclusions are common in quartz veins and pegmatites in metamorphic rocks and are more abundant in the hornfelses. The distribution of the different types of fluid inclusions suggests that CO₂ fluids generated during metamorphism and metamorphic fluids might also contribute to the formation of quartz veins and pegmatites in metamorphic terrains.     

Source rock potential of selected Cretaceous shales,Orange Basin,South Africa

Twenty Cretaceous shale samples from two wells in the Orange Basin of South Africa were evaluated for their source rock potential. They were sampled from within a 1400 m-thick sequence in boreholes drilled through Lower to Upper Cretaceous sediments. The samples exhibit total organic carbon (TOC) content of 1.06–2.17%; Rock-Eval S2 values of 0.08–2.27 mg HC/g; and petroleum source potential (SP), which is the sum of S1 and S2, of 0.10–2.61 mg HC/g, all indicating the presence of poor to fair hydrocarbon generative potential. Hydrogen index (HI) values vary from 7 to 128 mg HC/g organic carbon and oxygen index (OI) ranges from 37 to 195 mg CO₂/g organic carbon, indicating predominantly Type III kerogen with perhaps minor amounts of Type IV kerogen. The maturity of the samples, as indicated by T _max values of 428–446°C, ranges from immature to thermally mature with respect to oil generation. Measured vitrinite reflectance values (%Ro) of representative samples indicate that these samples vary from immature to mature, consistent with the thermal alteration index (TAI) (spore colour) and fluorescence data for these samples. Organic petrographic analysis also shows that amorphous organic matter is dominant in these samples. Framboidal pyrite is abundant and may be indicative of a marine influence during deposition. Although our Rock-Eval pyrolysis data indicate that gas-prone source rocks are prevalent in this part of the Orange Basin, the geochemical characteristics of samples from an Aptian unit at 3318 m in one of the wells suggest that better quality source rocks may exist deeper, in more distal depositional parts of the basin.     

Chemical variation from biolipids to sedimentary organic matter in modern oceans and its implication to the geobiological evaluation of ancient hydrocarbon source rocks

Understanding the dynamics of organic matter in modern marine water columns greatly favors the geobiological evaluation of hydrocarbon source rocks. Biolipids could make great contribution to petroleum hydrocarbons due to their comparable chemical components and the slightly refractory characteristics of biolipids during the microbial/thermal degradation. A variety of environmental factors such as temperature, CO₂ and salinity could affect the biochemical contents in microorganisms. As a result, microorganisms living in a changing environmental condition might have a different contribution to the petroleum formation. Organic carbon flux is shown to bear a positive correlation with the primary productivity only within a certain range of biomass volumes in a specific biohabitat. Furthermore, organic matter is degraded much quickly in a water column with oxic conditions. Therefore, the anoxic condition, along with the enhanced biological productivity, would be one of the significant factors in the formation of high-quality hydrocarbon source rocks. The formation of biofilms and microbial mats favors the preservation of sedimentary organic matter by decreasing the degradation rate of organic matter. Identification of biofilms and microbial mats in sedimentary rocks will thus greatly help to understand the depositional processes of organic matter finally preserved in hydrocarbon source rocks. __________ Translated from Earth Science—Journal of China University of Geosciences, 2007, 32(6): 748–754 [译自: 地球科学—中国地质大学学报     

Numerical simulation to quantify the leakage risk in a multi-layer aquifer system of pure brine recovery and CO<Subscript>2</Subscript>-enhanced brine recovery: a case study of potassium-rich brine recovery in Jianghan Basin of China

Deep brine recovery enhanced by supercritical CO₂ injection is proposed to be a win–win method for the enhancement of brine production and CO₂ storage capacity and security. However, the cross-flow through interlayers under different permeability conditions is not well investigated for a multi-layer aquifer system. In this work, a multi-layer aquifer system with different permeability conditions was built up to quantify the brine production yield and the leakage risk under both schemes of pure brine recovery and enhanced by supercritical CO₂. Numerical simulation results show that the permeability conditions of the interlayers have a significant effect on the brine production and the leakage risk as well as the regional pressure. Brine recovery enhanced by supercritical CO₂ injection can improve the brine production yield by a factor of 2–3.5 compared to the pure brine recovery. For the pure brine recovery, strong cross-flow through interlayers occurs due to the drastic and extensive pressure drop, even for the relative low permeability (k = 10^?20 m²) mudstone interlayers. Brine recovery enhanced by supercritical CO₂ can successfully manage the regional pressure and decrease the leakage risk, even for the relative high permeability (k = 10^?17 m²) mudstone interlayers. In addition, since the leakage of brine mainly occurs in the early stage of brine production, it is possible to minimize the leakage risk by gradually decreasing the brine production pressure at the early stage. Since the leakage of CO₂ occurs in the whole production period and is significantly influenced by the buoyancy force, it may be more effective by adopting horizontal wells and optimizing well placement to reduce the CO₂ leakage risk.     

Evaluation of the petroleum composition and quality with increasing thermal maturity as simulated by hydrous pyrolysis: A case study using a Brazilian source rock with Type I kerogen

Hydrous pyrolysis (HP) experiments were used to investigate the petroleum composition and quality of petroleum generated from a Brazilian lacustrine source rock containing Type I kerogen with increasing thermal maturity. The tested sample was of Aptian age from the Araripe Basin (NE-Brazil). The temperatures (280–360 °C) and times (12–132 h) employed in the experiments simulated petroleum generation and expulsion (i.e., oil window) prior to secondary gas generation from the cracking of oil. Results show that similar to other oil prone source rocks, kerogen initially decomposes in part to a polar rich bitumen, which decomposes in part to hydrocarbon rich oil. These two overall reactions overlap with one another and have been recognized in oil shale retorting and natural petroleum generation. During bitumen decomposition to oil, some of the bitumen is converted to pyrobitumen, which results in an increase in the apparent kerogen (i.e., insoluble carbon) content with increasing maturation.The petroleum composition and its quality (i.e., API gravity, gas/oil ratio, C₁₅₊ fractions, alkane distribution, and sulfur content) are affected by thermal maturation within the oil window. API gravity, C₁₅₊ fractions and gas/oil ratios generated by HP are similar to those of natural petroleum considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. API gravity of the HP expelled oils shows a complex relationship with increasing thermal maturation that is most influenced by the expulsion of asphaltenes. C₁₅₊ fractions (i.e., saturates, aromatics, resins and asphaltenes) show that expelled oils and bitumen are compositionally separate organic phases with no overlap in composition. Gas/oil ratios (GOR) initially decrease from 508–131 m³/m³ during bitumen generation and remain essentially constant (81–84 m³/m³) to the end of oil generation. This constancy in GOR is different from the continuous increase through the oil window observed in anhydrous pyrolysis experiments. Alkane distributions of the HP expelled oils are similar to those of natural crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous age. Isoprenoid and n-alkane ratios (i.e., pristane/n-C₁₇ and phytane/n-C₁₈) decrease with increasing thermal maturity as observed in natural crude oils. Pristane/phytane ratios remain constant with increasing thermal maturity through the oil window, with ratios being slightly higher in the expelled oils relative to those in the bitumen. Generated hydrocarbon gases are similar to natural gases associated with crude oils considered to be sourced from similar Brazilian lacustrine source rocks with Type I kerogen of Lower Cretaceous, with the exception of elevated ethane contents. The general overall agreement in composition of natural and hydrous pyrolysis petroleum of lacustrine source rocks observed in this study supports the utility of HP to better characterize petroleum systems and the effects of maturation and expulsion on petroleum composition and quality.