Hydrothermal control on organic matter alteration and illite precipitation, Mt Isa Basin, Australia

Abundant illite precipitation in Proterozoic rocks from Northern Lawn Hill Platform, Mt Isa Basin, Australia, occurred in organic matter‐rich black shales rather than in sandstones, siltstones and organic matter‐poor shales. Sandstones and siltstones acted as impermeable rocks, as early diagenetic quartz and carbonate minerals reduced the porosity–permeability. Scanning and transmission electron microscopy (SEM and TEM) studies indicate a relation between creation of microporosity–permeability and organic matter alteration, suitable for subsequent mineral precipitation. K–Ar data indicate that organic matter alteration and the subsequent illite precipitation within the organic matter occurred during the regional hydrothermal event at 1172 ± 50 (2σ) Ma. Hot circulating fluids are considered to be responsible for organic matter alteration, migration and removal of volatile hydrocarbon, and consequently porosity–permeability creation. Those rocks lacking sufficient porosity–permeability, such as sandstones, siltstones and organic matter poor shales, may not have been affected by fluid movement. In hydrothermal systems, shales and mudstones may not be impermeable as usually assumed because of hydrocarbons being rapidly removed by fluid, even with relatively low total organic carbon.     

Permeability evolution in sorbing media: analogies between organic‐rich shale and coal

Shale gas reservoirs like coalbed methane (CBM) reservoirs are promising targets for geological sequestration of carbon dioxide (CO₂). However, the evolution of permeability in shale reservoirs on injection of CO₂ is poorly understood unlike CBM reservoirs. In this study, we report measurements of permeability evolution in shales infiltrated separately by nonsorbing (He) and sorbing (CO₂) gases under varying gas pressures and confining stresses. Experiments are completed on Pennsylvanian shales containing both natural and artificial fractures under nonpropped and propped conditions. We use the models for permeability evolution in coal (Journal of Petroleum Science and Engineering, Under Revision) to codify the permeability evolution observed in the shale samples. It is observed that for a naturally fractured shale, the He permeability increases by approximately 15% as effective stress is reduced by increasing the gas pressure from 1 MPa to 6 MPa at constant confining stress of 10 MPa. Conversely, the CO₂ permeability reduces by a factor of two under similar conditions. A second core is split with a fine saw to create a smooth artificial fracture and the permeabilities are measured for both nonpropped and propped fractures. The He permeability of a propped artificial fracture is approximately 2‐ to 3fold that of the nonpropped fracture. The He permeability increases with gas pressure under constant confining stress for both nonpropped and propped cases. However, the CO₂ permeability of the propped fracture decreases by between one‐half to one‐third as the gas pressure increases from 1 to 4 MPa at constant confining stress. Interestingly, the CO₂ permeability of nonpropped fracture increases with gas pressure at constant confining stress. The permeability evolution of nonpropped and propped artificial fractures in shale is found to be similar to those observed in coals but the extent of permeability reduction by swelling is much lower in shale due to its lower organic content. Optical profilometry is used to quantify the surface roughness. The changes in surface roughness indicate significant influence of proppant indentation on fracture surface in the shale sample. The trends of permeability evolution on injection of CO₂ in coals and shales are found analogous; therefore, the permeability evolution models previously developed for coals are adopted to explain the permeability evolution in shales.     

Real‐time mud gas logging and sampling during drilling

Continuous mud gas loggings during drilling as well as offline mud gas sampling are standard procedures in oil and gas operations, where they are used to test reservoir rocks for hydrocarbons while drilling. Our research group has developed real‐time mud gas monitoring techniques for scientific drilling in non‐hydrocarbon formations mainly to sample and study the composition of crustal gases. We describe in detail this technique and provide examples for the evaluation of the continuous gas logs, which are not always easy to interpret. Hydrocarbons, helium, radon and with limitations carbon dioxide and hydrogen are the most suitable gases for the detection of fluid‐bearing horizons, shear zones, open fractures, sections of enhanced permeability and permafrost methane hydrate occurrences. Off‐site isotope studies on mud gas samples helped reveal the origin and evolution of deep‐seated crustal fluids.     

Gas breakthrough pressure for hydrocarbon reservoir seal rocks: implications for the security of long-term CO2 storage in the Weyburn field

This paper reports a laboratory study of the gas breakthrough pressure for different gas/liquid systems in the Mississippian‐age Midale Evaporite. This low‐permeability rock formation is the seal rock for the Weyburn Field in southeastern Saskatchewan, Canada, where CO₂ is being injected into an oil reservoir for enhanced recovery and CO₂ storage. A technique for experimentally determining CO₂ breakthrough pressure at reservoir conditions is presented. Breakthrough pressures for N₂, CO₂ and CH₄ were measured with the selected seal‐rock samples. The maximum breakthrough pressure is over 30 MPa for N₂ and approximately 21 MPa for CO₂. The experimental results demonstrate that the Weyburn Midale Evaporite seal rock is of high sealing quality. Therefore, the Weyburn reservoir and Midale Beds can be used as a CO₂ storage site after abandonment. The measured results also show that the breakthrough pressure of a seal rock for a gas is nearly proportional to the interfacial tension of the gas/brine system. The breakthrough pressure of a CO₂/brine system is significantly reduced compared with that of a CH₄/brine system because of the much lower interfacial tension of the former. This implies that a seal rock that seals the original gas in a gas reservoir or an oil reservoir with a gas cap may not be tight enough to seal the injected CO₂ if the pressure during or after CO₂ injection is the same or higher than the original reservoir pressure. Therefore, reevaluation of the breakthrough pressure of seal rocks for a given reservoir is necessary and of highest priority once it is chosen as a CO₂ storage site.     

Klinkenberg gas slippage measurements as a means for shale pore structure characterization

Established techniques that have been successfully used to characterize pore systems in conventional reservoir rocks lack the resolution and scalability required to adequately characterize the nano‐ to micrometer scale pore systems found in shale and cannot be applied on stressed samples. We have therefore investigated the utility of Klinkenberg gas slippage measurements for shale pore structure characterization. In contrast to other approaches, slippage measurements characterize the effective porosity of core samples and can be applied at stress conditions experienced in the reservoir during production. Slippage measurements on horizontally and vertically oriented samples from the Eagle Ford Shale Formation, Texas, USA, at a range of stress states revealed two orders of magnitude in slippage variation over five orders of magnitude permeability range. Slippage measurements are negatively correlated with permeability and follow similar trends to those found in other studies on higher permeability rocks. The samples had varying degrees of slippage anisotropy, which allowed interpretation of the relative contribution of tortuosity and pore size to permeability anisotropy. Slippage and therefore average effective pore size was found to vary up to one order of magnitude at a given permeability, warranting investigation of the significance this might have on flow properties and ultimately hydrocarbon production from shale.     

Physical properties of carbonate fault rocks,fucino basin (Central Italy): implications for fault seal in platform carbonates

We documented the porosity, permeability, pore geometry, pore type, textural anisotropy, and capillary pressure of carbonate rock samples collected along basin‐bounding normal faults in central Italy. The study samples consist of one Mesozoic platform carbonate host rock with low porosity and permeability, four fractured host rocks of the damage zones, and four fault rocks of the fault cores. The four fractured samples have high secondary porosity, due to elongated, connected, soft pores that provide fluid pathways in the damage zone. We modeled this zone as an elastic cracked medium, and used the Budiansky–O'Connell correlation to compute its permeability from the measured elastic moduli. This correlation can be applied only to fractured rocks with large secondary porosity and high‐aspect ratio pores. The four fault rock samples are made up of survivor clasts embedded in fine carbonate matrices and cements with sub‐spherical, stiff pores. The low porosity and permeability of these rocks, and their high values of capillary pressure, are consistent with the fault core sealing as much as 77 and 140 m of gas and oil columns, respectively. We modeled the fault core as a granular medium, and used the Kozeny–Carmen correlation, assigning the value of 5 to the Kozeny constant, to compute its permeability from the measured porosities and pore radii. The permeability structure of the normal faults is composed of two main units with unique hydraulic characteristics: a granular fault core that acts as a seal to cross‐fault fluid flow, and an elastic cracked damage zone that surrounds the core and forms a conduit for fluid flow. Transient pathways for along‐fault fluid flow may form in the fault core during seismic faulting due to the formation of opening‐mode fractures within the cemented fault rocks.     

Effective gas permeability of Tight Gas Sandstones as a function of capillary pressure – a non‐steady‐state approach

Single‐ and two‐phase (gas/water) fluid transport in tight sandstones has been studied in a series of permeability tests on core plugs of nine tight sandstones of the southern North Sea. Absolute (Klinkenberg‐corrected) gas permeability coefficients (k_gas__inf) ranged between 3.8 × 10^?16 and 6.2 × 10^?19 m² and decreased with increasing confining pressure (10–30 MPa) by a factor 3–5. Klinkenberg‐corrected (intrinsic) gas permeability coefficients were consistently higher by factors from 1.4 to 10 than permeability coefficients determined with water. Non‐steady‐state two‐phase (He/water) flow experiments conducted up to differential pressures of 10 MPa document the dynamically changing conductivity for the gas phase, which is primarily capillary‐controlled (drainage and imbibition). Effective gas permeability coefficients in the two‐phase flow tests ranged between 1.1 × 10^?17 and 2.5 × 10^?22 m², corresponding to relative gas permeabilities of 0.03% and 10%. In the early phase of the nonstationary flow regime (before establishment of steady‐state conditions), they may be substantially (>50%) lower. Effective gas permeability measurements are affected by the following factors: (i) Capillary‐controlled drainage/imbibition, (ii) viscous–dynamic effects (iii) and slip flow.     

Evolution of porosity, permeability and fluid pressure in dilatant faults post-failure: implications for fluid flow and mineralization

Mineralization of brittle fault zones is associated with sudden dilation, and the corresponding changes in porosity, permeability and fluid pressure, that occur during fault slip events. The resulting fluid pressure gradients cause fluid to flow into and along the fault until it is sealed. The volume of fluid that can pass through the deforming region depends on the degree of dilation, the porosity and permeability of the fault and wall rocks, and the rate of fault sealing. A numerical model representing a steep fault cutting through a horizontal seal is used to investigate patterns of fluid flow following a dilatant fault slip event. The model is initialized with porosity, permeability and fluid pressure representing the static mechanical state of the system immediately after such an event. Fault sealing is represented by a specified evolution of porosity, coupled to changes in permeability and fluid pressure, with the rate of porosity reduction being constrained by independent estimates of the rate of fault sealing by pressure solution. The general pattern of fluid flow predicted by the model is of initial flow into the fault from all directions, followed by upward flow driven by overpressure beneath the seal. The integrated fluid flux through the fault after a single failure event is insufficient to account for observed mineralization in faults; mineralization would require multiple fault slip events. Downward flow is predicted if the wall rocks below the seal are less permeable than those above. This phenomenon could at least partially explain the occurrence of uranium deposits in reactivated basement faults that cross an unconformity between relatively impermeable basement and overlying sedimentary rocks.     

Gas breakthrough experiments on fine-grained sedimentary rocks

The capillary sealing efficiency of fine‐grained sedimentary rocks has been investigated by gas breakthrough experiments on fully water saturated claystones and siltstones (Boom Clay from Belgium, Opalinus Clay from Switzerland and Tertiary mudstone from offshore Norway) of different lithological compositions. Sand contents of the samples were consistently below 12%, major clay minerals were illite and smectite. Porosities determined by mercury injection lay between 10 and 30% while specific surface areas determined by nitrogen adsorption (BET method) ranged from 20 to 48 m² g ^{? 1}. Total organic carbon contents were below 2%. Prior to the gas breakthrough experiments the absolute (single phase) permeability (k_abs) of the samples was determined by steady state flow tests with water or NaCl brine. The k_abs values ranged between 3 and 550 nDarcy (3 × 10^?21 and 5.5 × 10^?19 m²). The maximum effective permeability to the gas‐phase (k_eff) measured after gas breakthrough on initially water‐saturated samples extended from 0.01 nDarcy (1 × 10^?23 m²) up to 1100 nDarcy (1.1 × 10^?18 m²). The residual differential pressures after re‐imbibition of the water phase, referred to as the ‘minimum capillary displacement pressures’ (P_d), ranged from 0.06 to 6.7 MPa. During the re‐imbibition process the effective permeability to the gas phase decreases with decreasing differential pressure. The recorded permeability/pressure data were used to derive the pore size distribution (mostly between 8 and 60 nm) and the transport porosity of the conducting pore system (10^‐5–10^‐2%). Correlations could be established between (i) absolute permeability coefficients and the maximum effective permeability coefficients and (ii) effective or absolute permeability coefficients and capillary sealing efficiency. No correlation was found between the capillary displacement pressures determined from gas breakthrough experiments and those derived theoretically by mercury injection.     

Source of ore fluids at the Kalahari Goldridge deposit, Kraaipan greenstone belt, South Africa: evidence from Sr, C and O isotope signatures in carbonates

The Kalahari Goldridge deposit is located in the Archaean Kraaipan greenstone belt in the north-west province of South Africa. Gold mineralization in this deposit is hosted within banded iron formation which is flanked by a mafic schist in the footwall and clastic metasedimentary units in the hanging wall. Data from carbonate minerals from mineralized veins and bulk rock from the A and D zone ore bodies have helped to define the ultimate origin of the ore-forming fluids and their migration history. Carbon isotope ratios of carbonates from both the A and D zone ore bodies have tight clustering from −7.6 to −5.3‰ that indicates a unique origin for the ore-forming fluids associated with the mineralization at Kalahari Goldridge. The δ¹⁸O values of the carbonates have been influenced by temperature gradients and variable degrees of fluid–rock interaction promoting oxygen isotope exchange between ore fluid and host rocks. Minimum ⁸⁷Sr/⁸⁶Sr ratio values of 0.70354 in mineralized veins are most consistent with ore-forming fluids being relatively pristine with a mantle origin. Strontium and the corresponding ore-forming fluids were most likely derived from mantle-derived magmatic rocks probably represented by the meta-basaltic rocks that underlie the ferruginous package in the Kraaipan greenstone belt. Strontium isotopic composition of vein carbonates show considerable variation in ⁸⁷Sr/⁸⁶Sr ratios ranging from 0.70354 to 0.73914. This is consistent with an ore fluid composition that has been modified by the addition of radiogenic Sr possibly during passage of fluid through siliciclastic country rock concomitant with the observed hydrothermal alteration.     

Stress‐dependent transport properties of fractured arkosic sandstone

We measure the fluid transport properties of microfractures and macrofractures in low‐porosity polyphase sandstone and investigate the controls of in situ stress state on fluid flow conduits in fractured rock. For this study, the permeability and porosity of the Punchbowl Formation sandstone, a hydrothermally altered arkosic sandstone, were measured and mapped in stress space under intact, microfractured, and macrofractured deformation states. In contrast to crystalline and other sedimentary rocks, the distributed intragranular and grain‐boundary microfracturing that precedes macroscopic fracture formation has little effect on the fluid transport properties. The permeability and porosity of microfractured and intact sandstone depend strongly on mean stress and are relatively insensitive to differential stress and proximity to the frictional sliding envelope. Porosity variations occur by elastic pore closure with intergranular sliding and pore collapse caused by microfracturing along weakly cemented grain contacts. The macroscopic fractured samples are best described as a two‐component system consisting (i) a tabular fracture with a 0.5‐mm‐thick gouge zone bounded by 1 mm thick zones of concentrated transgranular and intragranular microfractures and (ii) damaged sandstone. Using bulk porosity and permeability measurements and finite element methods models, we show that the tabular fracture is at least two orders of magnitude more permeable than the host rock at mean stresses up to 90 MPa. Further, we show that the tabular fracture zone dilates as the stress state approaches the friction envelope resulting in up to a three order of magnitude increase in fracture permeability. These results indicate that the enhanced and stress‐sensitive permeability in fault damage zones and sedimentary basins composed of arkosic sandstones will be controlled by the distribution of macroscopic fractures rather than microfractures.     

Geochemistry and origin of natural gases dissolved in brines from gas fields in southwest Japan

Previous geochemical studies indicated that most natural gases dissolved in brines in Japan are of microbial origin, consisting of methane produced via carbonate reduction. However, some of those from gas fields in southwest Japan contain methane relatively enriched in ¹³C, whose origin remains to be clarified. To address this issue, chemical and isotopic analyses were performed on natural gases and brines from the gas fields in Miyazaki and Shizuoka prefectures, southwest Japan. Methane isotopic signatures (δ¹³C ≈ ?68‰ to ?34‰ VPDB; δ²H ≈ ?183‰ to ?149‰ VSMOW) suggest that these gases are of microbial (formed via carbonate reduction) or of mixed microbial and thermogenic origin. The relatively high δ²H‐CH₄ values and their relationship with the δ²H‐H₂O values argue against the possibility of their formation via acetate fermentation. The δ¹³C‐CO₂ values (≈?5‰), together with the slope of the correlation between δ²H‐CH₄ and δ¹³C‐CH₄ (Δδ²H‐CH₄/Δδ¹³C‐CH₄ ≈ 1), contradict the possibility of their formation via carbonate reduction followed by partial oxidation by methanotrophs. The ³He/⁴He ratios of the gases from Miyazaki (≈0.11–1.3 Ra) and their low correlation with δ¹³C‐CH₄ values do not support an abiogenic origin. It is inferred therefore that the high δ¹³C‐CH₄ values of natural gases dissolved in brines from gas fields in southwest Japan are indications of the contribution of thermogenic hydrocarbons, although whether abiogenic hydrocarbons contribute significantly to the gases from Shizuoka requires further investigation. This study has clarified that, for the future exploration of natural gases in southwest Japan, we should adopt the strategies for conventional thermogenic gas accumulations, such as checking the content, type and maturity of organic matter in the underlying sedimentary rocks.     

Meteorological influences on the spatial and temporal variability of NO2 in Toronto and Hamilton

The spatial and temporal variability of nitrogen dioxide (NO₂) concentrations and their relationships with meteorology was evaluated in the Toronto–Hamilton urban airshed. NO₂ concentrations were highest in the early morning and late evening. Mean concentrations were highest in winter, although individual one-hour NO₂ concentrations were found to be highest in summer. Wind direction was the strongest control on hourly NO₂ concentration, and temperature and wind speed also had an effect. Our analysis of NO₂ concentration variation by wind direction showed that areas downwind of major highways, urban centres and industry were exposed to higher pollutant concentrations. Seasonal patterns of NO₂ concentration displayed significant spatial heterogeneity, in particular, in Toronto. Onshore winds sheltered coastal inhabitants from the full extent of NO₂ exposure they would otherwise experience. Seasonal variations in meteorology and emissions mean that the degree of spatial variability in NO₂ concentrations changes from season to season. This study will help to improve existing land-use regression-based NO₂ prediction models by incorporating meteorological controls on NO₂ distributions for health effect studies.     

A Supplemental Indicator of High-Value or Low-Value Spatial Clustering

Most test statistics for detecting spatial clustering cannot distinguish between low-value spatial clustering and high-value spatial clustering, and none is designed to explicitly detect high-value clustering, low-value clustering, or both. To fill this void in practice, we introduce an adjustment procedure that can supplement common two-sided spatial clustering tests so that a one-sided conclusion can be reached. The procedure is applied to Moran's I and Tango's C _G in both simulated and real-world spatial patterns. The results show that the adjustment procedure can account for the influence of low-value clusters on high-value clustering and vice versa. The procedure has little effect on the original global testing methods when there is no clustering. When there is a clustering tendency, the procedure can unambiguously distinguish the existence of high-value clusters or low-value clusters or both.     

Gas breakthrough experiments on pelitic rocks: comparative study with N2, CO2 and CH4

The capillary‐sealing efficiency of intermediate‐ to low‐permeable sedimentary rocks has been investigated by N₂, CO₂ and CH₄ breakthrough experiments on initially fully water‐saturated rocks of different lithological compositions. Differential gas pressures up to 20 MPa were imposed across samples of 10–20 mm thickness, and the decline of the differential pressures was monitored over time. Absolute (single‐phase) permeability coefficients (k_abs), determined by steady‐state fluid flow tests, ranged between 10^?22 and 10^?15 m². Maximum effective permeabilities to the gas phase k_eff(max), measured after gas breakthrough at maximum gas saturation, extended from 10^?26 to 10^?18 m². Because of re‐imbibition of water into the interconnected gas‐conducting pore system, the effective permeability to the gas phase decreases with decreasing differential (capillary) pressure. At the end of the breakthrough experiments, a residual pressure difference persists, indicating the shut‐off of the gas‐conducting pore system. These pressures, referred to as the ‘minimum capillary displacement pressures’ (P_d), ranged from 0.1 up to 6.7 MPa. Correlations were established between (i) absolute and effective permeability coefficients and (ii) effective or absolute permeability and capillary displacement pressure. Results indicate systematic differences in gas breakthrough behaviour of N₂, CO₂ and CH₄, reflecting differences in wettability and interfacial tension. Additionally, a simple dynamic model for gas leakage through a capillary seal is presented, taking into account the variation of effective permeability as a function of buoyancy pressure exerted by a gas column underneath the seal.     

Loglinear Residual Tests of Moran's I Autocorrelation and their Applications to Kentucky Breast Cancer Data

This article bridges the permutation test of Moran's I to the residuals of a loglinear model under the asymptotic normality assumption. It provides the versions of Moran's I based on Pearson residuals ( I _PR) and deviance residuals ( I _DR) so that they can be used to test for spatial clustering while at the same time account for potential covariates and heterogeneous population sizes. Our simulations showed that both I _PR and I _DR are effective to account for heterogeneous population sizes. The tests based on I _PR and I _DR are applied to a set of log-rate models for early-stage and late-stage breast cancer with socioeconomic and access-to-care data in Kentucky. The results showed that socioeconomic and access-to-care variables can sufficiently explain spatial clustering of early-stage breast carcinomas, but these factors cannot explain that for the late stage. For this reason, we used local spatial association terms and located four late-stage breast cancer clusters that could not be explained. The results also confirmed our expectation that a high screening level would be associated with a high incidence rate of early-stage disease, which in turn would reduce late-stage incidence rates.     

ALUMINA AND CALCIUM OXIDE CONTENT OF GLASS FOUND IN WESTERN AND NORTHERN EUROPE, FIRST TO NINTH CENTURIES

Summary. The glass of Gallo-roman origin and that considered as coming from the several centuries after the disintegration of the Roman empire has much the same composition in examples found in northern and western Europe. The components calcium oxide and alumina (CaO and Al₂O₃) increase or decrease together. Compositional variation between different samples from this geographic area are not much greater than those at a single site of manufacture. Contamination during the manufacture process is unlikely to account for the CaO and Al₂O₃ contents in glass from this period according to analyses of glass adhering to crucibles or fusion pots. CaO and Al₂O₃ were apparently added intentionally to the glass composition. A slight tendency to an increase in these oxides is accompanied by a decrease in Na₂O content which might be due to a loss through volatilization during re-workings. Such a trend is apparent in the eighth to ninth century samples. The remarkably constant composition of glass found in a wide area for objects produced over a long period of time suggests that a limited number of production sites existed for either the raw materials or the confection of raw glass which was fashioned at various other sites.     

Quantitative estimation of overpressure caused by gas generation and application to the Baiyun Depression in the Pearl River Mouth Basin,South China Sea

Hydrocarbon generation can yield high fluid pressures in sedimentary basins as the conversion of solid kerogen to hydrocarbons can result in an increase in fluid volume. To quantify the relationship between gas generation and overpressure in source rocks, a set of equations for computing the pressure change due to gas generation has been derived. Those equations can be used to quantitatively estimate overpressure generated by type III kerogen in source rocks by considering gas generation and leakage, gas dissolution in formation water and residual oil, thermal cracking of oil to gas, and hydrocarbon episodic expulsion from source rocks. The equations also take consideration of other factors including source rock porosity, transformation ratio, total organic carbon (TOC), hydrogen index, and compressibility of kerogen, oil, and water. As both oil and gas are taken into account in the equations, they can also be used to estimate the evolution of overpressure caused by hydrocarbon generation of type I and type II kerogen source rocks. Sensitivity analyses on the type III kerogen source rock indicate that hydrogen index is the most influential parameter for overpressure generation, while TOC and residual gas coefficient (β: ratio of residual gas over the total gas generated) have a moderate effect. Overpressure can be generated even if the gas leakage/loss in the source rock is up to 80% of the total gas generated. This suggests that the internal pressure seal of the source rock is not a critical factor on the pressure change as long as the source rocks are capable of sealing liquid oil. The equations were applied to evaluate the overpressure in the Eocene–Oligocene Enping Formation source rocks due to hydrocarbon generation in the Baiyun Depression, the Pearl River Mouth Basin by considering the source rock properties, hydrocarbon generation history, and hydrocarbon expulsion timing. Two episodes of overpressure development due to gas generation and release were modeled to have occurred in the Enping Formation source rock since 16 Ma. The overpressure release at 10.2–5.3 Ma via hydrocarbon expulsion was apparently related to the Dongsha phase of tectonic deformation, whereas the pressure release at 2–0 Ma was due to pressure generation that was exceeded the fracture‐sealing pressure in the source rocks.     

Maintaining high fluid pressures in older sedimentary basins

High fluid pressures in old geologic basins, where the mechanisms that generate high fluid pressure have ceased to operate, pose the problem of how high fluid pressures are maintained through geologic time. Recent oil and gas exploration reveals that low permeability shales, the source beds for oil and gas, contain large quantities of gas that are now being exploited in many sedimentary basins in North America. No earlier analyses of how to maintain high fluid pressure in older sedimentary basins included a shale bed as a source of adsorbed gas; this is a new conceptual element that will fundamentally change the analysis. Such a large fluid source can compensate for a low rate of bleed off in a dynamic system. If the fluid source is large enough, as the gas within these shale source beds appears to be, there will no appreciable drop in pressure accompanying a low rate of leakage from the basin for long periods. For the dynamic school of basin analysts this may provide the missing piece in the puzzle, explaining how high fluid pressures are maintained for long periods of geologic time in a crust with finite, non-zero permeability. This is a hypothesis which needs to be tested by new basin analyses.     

The salt chimney effect: delay of thermal evolution of deep hydrocarbon source rocks due to high thermal conductivity of evaporites

Half of the topseals to the world's largest oilfields are evaporites. Rock salt has a thermal conductivity two to four times greater than that of other sedimentary rocks found in oil‐ and gas‐bearing basins. Strong heat conduction through evaporites can increase the geothermal gradient above evaporite deposits, resulting in a positive thermal anomaly and above‐average temperature while simultaneously decreasing the geothermal gradient below evaporites, resulting in a negative thermal anomaly. Most Triassic–Jurassic hydrocarbon source rocks in the Kuqa Basin, western China, are overlain by ~1500‐m‐thick Tertiary evaporites with underlying Cretaceous sandstones and mudstones. Directly measured strata temperatures indicate an obvious break in the steepness of the geothermal gradient above and below Paleogene evaporites, with a significantly steeper geothermal gradient above the evaporites. Simulations of the thermal evolution of source rocks based on data collected from well Kela‐2 indicate that if the thickness of evaporites (mainly rock salt and anhydrite rock) in overlying rocks above source rocks increases compared with the thickness of siliciclastic rocks in the overlying rocks, then strata temperatures and vitrinite reflectance in Jurassic source rocks will decrease accordingly. Our thermal simulations based on the thickness and thermal conductivity of evaporites accurately coincide with previous studies based on homogenization temperatures, hydrocarbon–water contact retrospection, and carbon isotope results from natural gases. The gas generation center located in the Kalasu Tectonic Belt today is also sealed in an evaporite‐related structural trap that formed at this time. Therefore, the speculated natural gas generation times not only correlate with the evaporite‐related structural trap formation, but the calculated maturity of deep source rocks below the evaporites also coincides with current gas reserves. And our studies can help to find the deep oils and gases under thick evaporites.