Downward hydrocarbon migration predicted from numerical modeling of fluid overpressure in the Paleozoic Anticosti Basin,eastern Canada

The Anticosti Basin is a large Paleozoic basin in eastern Canada where potential source and reservoir rocks have been identified but no economic hydrocarbon reservoirs have been found. Potential source rocks of the Upper Ordovician Macasty Formation overlie carbonates of the Middle Ordovician Mingan Formation, which are underlain by dolostones of the Lower Ordovician Romaine Formation. These carbonates have been subjected to dissolution and dolomitization and are potential hydrocarbon reservoirs. Numerical simulations of fluid‐overpressure development related to sediment compaction and hydrocarbon generation were carried out to investigate whether hydrocarbons generated in the Macasty Formation could migrate downward into the underlying Mingan and Romaine formations. The modeling results indicate that, in the central part of the basin, maximum fluid overpressures developed above the Macasty Formation due to rapid sedimentation. This overpressured core dissipated gradually with time, but the overpressure pattern (i.e. maximum overpressure above source rock) was maintained during the generation of oil and gas. The downward impelling force associated with fluid‐overpressure gradients in the central part of the basin was stronger than the buoyancy force for oil, whereas the buoyancy force for gas and for oil generated in the later stage of the basin is stronger than the overpressure‐related force. Based on these results, it is proposed that oil generated from the Macasty Formation in the central part of the basin first moved downward into the Mingan and Romaine formations, and then migrated laterally up‐dip toward the basin margin, whereas gas throughout the basin and oil generated in the northern part of the basin generally moved upward. Consequently, gas reservoirs are predicted to occur in the upper part of the basin, whereas oil reservoirs are more likely to be found in the strata below the source rocks. Geofluids (2010) 10 , 334–350     

Hydraulic and hydrochemical properties of deep sedimentary reservoirs of the Upper Rhine Graben,Europe

Hydraulic and hydrochemical data from several hundred wells mostly drilled by the oil and gas industry within the four deep carbonate and siliciclastic reservoirs of the Upper Rhine Graben area in France and Germany have been compiled, examined, validated and analysed with the aim to characterize fluids and reservoir properties. Due to enhanced temperatures in the subsurface of the Upper Rhine Graben, this study on hydraulic and hydrochemical properties has been motivated by an increasing interest in deep hydrogeothermal energy projects in the Rhine rift valley. The four examined geothermal reservoir formations are characterized by high hydraulic conductivity reflecting the active tectonic setting of the rift valley and its fractured and karstified reservoirs. The hydraulic conductivity decreases only marginally with depth in each of the reservoirs, because the Upper Rhine Graben is a young tectonically active structure. The generally high hydraulic conductivity of the reservoir rocks permits cross‐formation advective flow of thermal water. Water composition data reflect the origin and hydrochemical evolution of deep water. Shallow water to 500 m depth is, in general, weakly mineralized. The chemical signature of the water is controlled by fluid–rock geochemical interactions. With increasing depth, the total of dissolved solids (TDS) increases. In all reservoirs, the fluids evolve to a NaCl‐dominated brine. The high salinity of the reservoirs is partly derived from dissolution of halite in evaporitic Triassic and Cenozoic formations, and partly from the fluids residing in the crystalline basement. Water of all four reservoirs is saturated with respect to calcite and other minerals including quartz and barite.     

Reactive transport and thermo‐hydro‐mechanical coupling in deep sedimentary basins affected by glaciation cycles: model development,verification, and illustrative example

Deep sedimentary basins are complex systems that over long time scales may be affected by numerous interacting processes including groundwater flow, heat and mass transport, water–rock interactions, and mechanical loads induced by ice sheets. Understanding the interactions among these processes is important for the evaluation of the hydrodynamic and geochemical stability of geological CO₂ disposal sites and is equally relevant to the safety evaluation of deep geologic repositories for nuclear waste. We present a reactive transport formulation coupled to thermo‐hydrodynamic and simplified mechanical processes. The formulation determines solution density and ion activities for ionic strengths ranging from freshwater to dense brines based on solution composition and simultaneously accounts for the hydro‐mechanical effects caused by long‐term surface loading during a glaciation cycle. The formulation was implemented into the existing MIN3P reactive transport code (MIN3P‐THCm) and was used to illustrate the processes occurring in a two‐dimensional cross section of a sedimentary basin subjected to a simplified glaciation scenario consisting of a single cycle of ice‐sheet advance and retreat over a time period of 32 500 years. Although the sedimentary basin simulation is illustrative in nature, it captures the key geological features of deep Paleozoic sedimentary basins in North America, including interbedded sandstones, shales, evaporites, and carbonates in the presence of dense brines. Simulated fluid pressures are shown to increase in low hydraulic conductivity units during ice‐sheet advance due to hydro‐mechanical coupling. During the period of deglaciation, Darcy velocities increase in the shallow aquifers and to a lesser extent in deeper high‐hydraulic conductivity units (e.g., sandstones) as a result of the infiltration of glacial meltwater below the warm‐based ice sheet. Dedolomitization is predicted to be the most widespread geochemical process, focused near the freshwater/brine interface. For the illustrative sedimentary basin, the results suggest a high degree of hydrodynamic and geochemical stability.     

Fluid environment for preservation of pore spaces in a deep dolomite reservoir

Well TS1 reveals many uncemented pores and vugs at depths of more than 8000 m in a deep Cambrian dolomite reservoir in the Tarim Basin, northwestern China. The fluid environment and mechanism required for the preservation of reservoir spaces have yet not been well constrained. Carbon, oxygen, and strontium isotope compositions and fluid inclusion data suggest two types of fluids, meteoric water and hydrothermal fluid, affecting the Lower Paleozoic carbonate reservoirs in the Tarim Basin. Based on simulation using a thermodynamic model for H₂O‐CO₂‐NaCl‐CaCO₃ system, meteoric water has the ability to continuously dissolve carbonate minerals during downward migration from the surface to deep strata until it reaches a transition depth, below which it will begin to precipitate carbonate minerals to fill preexisting pore spaces. In contrast, hydrothermal fluid has the ability to dissolve carbonate in deep strata and precipitate carbonate in shallow strata during upward migration. Based on the dissolution–precipitation characteristics of the two types of fluids, the ideal fluid environment for the preservation of preexisting reservoir spaces occurs when carbonate reservoir is neither in the CaCO₃ precipitation domain of meteoric water nor in the CaCO₃ precipitation domain of hydrothermal fluid. Taking the Lower Paleozoic carbonate reservoirs in the north uplift area as an example, the spaces in the deep Cambrian dolomite reservoir near well TS1 were seldom filled because thick Ordovician deposits blocked meteoric water from migrating downward into the Cambrian dolomite reservoir and because the Cambrian dolomite reservoir has been in the domain of hydrothermal dissolution since the Permian. The deep carbonate layers in basins elsewhere with a similar fluid environment may have high uncemented porosity and consequently have good hydrocarbon exploration potential.     

Impacts of Pleistocene glaciation on large‐scale groundwater flow and salinity in the Michigan Basin

Pleistocene melting of kilometer‐thick continental ice sheets significantly impacted regional‐scale groundwater flow in the low‐lying stable interiors of the North American and Eurasian cratons. Glacial meltwaters penetrated hundreds of meters into the underlying sedimentary basins and fractured crystalline bedrock, disrupting relatively stagnant saline fluids and creating a strong disequilibrium pattern in fluid salinity. To constrain the impact of continental glaciation on variable density fluid flow, heat and solute transport in the Michigan Basin, we constructed a transient two‐dimensional finite‐element model of the northern half of the basin and imposed modern versus Pleistocene recharge conditions. The sag‐type basin contains up to approximately 5 km of Paleozoic strata (carbonates, siliciclastics, and bedded evaporites) overlain by a thick veneer (up to 300 m) of glacial deposits. Formation water salinity increases exponentially from <0.5 g l^?1 total dissolved solids (TDS) near the surface to >350 g l^?1 TDS at over 800 m depth. Model simulations show that modern groundwater flow is primarily restricted to shallow glacial drift aquifers with discharge to the Great Lakes. During the Pleistocene, however, high hydraulic heads from melting of the Laurentide Ice Sheet reversed regional flow patterns and focused recharge into Paleozoic carbonate and siliciclastic aquifers. Dilute waters (<20 g l^?1 TDS) migrated approximately 110 km laterally into the Devonian carbonate aquifers, significantly depressing the freshwater‐saline water mixing zones. These results are consistent with ¹⁴C ages and oxygen isotope values of confined groundwaters in Devonian carbonates along the basin margin, which reflect past recharge beneath the Laurentide Ice Sheet (14–50 ka). Constraining the paleohydrology of glaciated sedimentary basins, such as the Michigan Basin, is important for determining the source and residence times of groundwater resources, in addition to resolving geologic forces responsible for basinal‐scale fluid and solute migration.     

Overpressure in the Malay Basin and prediction methods

Predrill overpressure prediction is important for well planning and migration modeling for prospect evaluation. The Eaton (Journal of Petroleum Technology, 24 , 1972, 929) and Bowers (SPE Drilling & Completion, 10 , 1995, 89) methods are used worldwide for postdrill overpressure prediction using sonic log and predrill overpressure prediction using seismic interval velocity. In this research, these two methods were used for overpressure prediction using 3D anisotropic prestack depth‐migrated seismic interval velocity in a field of the Malay Basin. In the shallow overpressured zone, where the mechanism of overpressure is undercompaction, the onset of overpressure was predicted reasonably well using the Eaton and Bowers methods with their standard parameters (i.e., Eaton exponent 3 and Bowers loading curve) for seismic velocity. However, in the deep overpressured zone, where fluid expansion is the cause of overpressure generation, these methods underpredicted the high overpressure. In the deep overpressured zone, the overpressures were better predicted by applying a correction to the Eaton method. On the other hand, the Bowers unloading parameters for the fluid expansion mechanisms did not show any significant effect on overpressure prediction. Hence, in the study area, the Bowers method is not effective for 3D overpressure prediction using seismic velocity, whereas the Eaton method is more robust and can be used for 3D overpressure prediction from seismic velocity.     

Numerical modeling of the origin of calcite mineralization in the Refugio‐Carneros fault,Santa Barbara Basin,California

Many faults in active and exhumed hydrocarbon‐generating basins are characterized by thick deposits of carbonate fault cement of limited vertical and horizontal extent. Based on fluid inclusion and stable isotope characteristics, these deposits have been attributed to upward flow of formation water and hydrocarbons. The present study sought to test this hypothesis by using numerical reactive transport modeling to investigate the origin of calcite cements in the Refugio‐Carneros fault located on the northern flank of the Santa Barbara Basin of southern California. Previous research has shown this calcite to have low δ¹³C values of about ?40 to ?30‰PDB, suggesting that methane‐rich fluids ascended the fault and contributed carbon for the mineralization. Fluid inclusion homogenization temperatures of 80–125°C in the calcite indicate that the fluids also transported significant quantities of heat. Fluid inclusion salinities ranging from fresh water to seawater values and the proximity of the Refugio‐Carneros fault to a zone of groundwater recharge in the Santa Ynez Mountains suggest that calcite precipitation in the fault may have been induced by the oxidation of methane‐rich basinal fluids by infiltrating meteoric fluids descending steeply dipping sedimentary layers on the northern basin flank. This oxidation could have occurred via at least two different mixing scenarios. In the first, overpressures in the central part of the basin may have driven methane‐rich formation waters derived from the Monterey Formation northward toward the basin flanks where they mixed with meteoric water descending from the Santa Ynez Mountains and diverted upward through the Refugio‐Carneros fault. In the second scenario, methane‐rich fluids sourced from deeper Paleogene sediments would have been driven upward by overpressures generated in the fault zones because of deformation, pressure solution, and flow, and released during fault rupture, ultimately mixing with meteoric water at shallow depth. The models in the present study were designed to test this second scenario, and show that in order for the observed fluid inclusion temperatures to be reached within 200 m of the surface, moderate overpressures and high permeabilities were required in the fault zone. Sudden release of overpressure may have been triggered by earthquakes and led to transient pulses of accelerated fluid flow and heat transport along faults, most likely on the order of tens to hundreds of years in duration. While the models also showed that methane‐rich fluids ascending the Refugio‐Carneros fault could be oxidized by meteoric water traversing the Vaqueros Sandstone to form calcite, they raised doubts about whether the length of time and the number of fault pulses needed for mineralization by the fault overpressuring mechanism were too high given existing geologic constraints.     

Influence of fault map resolution on pore pressure distribution and secondary hydrocarbon migration; Tune area,North Sea

Pressure and hydrocarbon migration modelling was carried out in the Tune Field area, Viking Graben, offshore Norway. The pressures are considered to be controlled by compartments bounded by mapped faults. Two different interpreted fault maps at the top reservoir level (Brent Group) are used as input to the modelling. First, a low‐resolution fault map is used, with only the large faults interpreted, and next, both large and small faults are included. The simulations show high overpressures generated in the western area, in the deeper part of the Viking Graben, and hydrostatic in the eastern areas. A sharp transition zone results from using the low‐resolution fault map in the simulations. Small N–S striking faults situated in between the wells have to have higher sealing capacity than expected from juxtaposition analysis alone, to be able to match the overpressures measured in well 30/5‐2 and 30/8‐1S in the Tune Field, and well 30/8‐3 east of Tune. The intermediate pressure in the western part is probably related to flow in the deeper parts of the sedimentary column in the compartment, where well 30/8‐3 is situated. The secondary oil migration models show that overpressures have major effects on the migration pathways of hydrocarbons. The level of detail in the fault interpretation is important for simulation results, both for pressure distribution and for hydrocarbon migration.     

Groundwater age,brine migration,and large‐scale solute transport in the Alberta Basin,Canada

There is a great contrast in geochemical and hydrogeologic estimates of the residence times of pore fluids in sedimentary basins. This contrast is particularly evident in the Alberta Basin, Canada, which has served as the study area for important studies of long‐term fluid flow and transport. To address these differences, we developed two‐dimensional simulations of groundwater age, constrained by both hydrogeologic and geochemical observations, to estimate the residence time of fluids and the amount and timing of flushing by meteoric waters in the Alberta Basin. Results suggest that old, residual brines have been retained in the deepest parts of the basin since their formation ca. 400 Ma, but significant dilution by younger waters has reduced the age of these pore waters to no more than approximately 200 My. Shallower formations have been flushed extensively by fresh, young waters. Loss of brines and dilution of older pore waters occurred primarily after the uplift of the Rockies with the introduction of the gravity‐driven flow regime. Despite these large changes in flow regime, solute exchange between deep saline aquifers and the overlying vigorous freshwater flow system was found to be consistent with long‐term dispersive mixing across subhorizontal concentration gradients rather than by direct flushing. Sensitivity studies using an analytic solution supported the use of 100 m for transverse dispersivity in large‐scale numerical models. These simulations confirm that the age and origin of brines are in many cases poor indicators of long‐term solute transport rates in sedimentary basins, but the geochemical indicators that are used to determine the origin of brines can provide useful constraints for calculating groundwater age and are far more commonly available than isotopic groundwater age tracers.     

The stress regime of the Western Canadian Sedimentary Basin

All available information relevant to in situ stress orientations and magnitudes in the Western Canadian Sedimentary Basin (WCSB) were examined to provide a better understanding of how regional stress fields may affect geothermal development. The smallest principal stress is horizontal over most of the Western Canadian Sedimentary Basin, and it varies in magnitude across the region. Horizontal stress trajectories show that S_Hmax axes are generally aligned SW–NE. A total of 1643 measurements of microfracture and minifracture closure pressures, leak‐off pressures and fracture breakdown pressures have been harnessed to map S_Hmin gradients across the basin at depths of 156–500, 500–1000, 1000–4185 and 2000–4185 m. Vertical stress magnitudes, calculated in 91 wells, showed that at constant depth, S_V increases towards the Canadian Rocky Mountains. Resultant regional stress maps show consistent trends in orientation of stress axes. As a result, predictions can be made that propagation axes of subsurface hydraulic fractures will be dominantly SW–NE, except over the Peace River Arch area, where they will trend more towards SSW–NNE. Engineered geothermal systems in the WCSB can be optimised by drilling horizontal wells parallel to S_Hmin.     

Can argillaceous formations isolate nuclear waste? Insights from isotopic,noble gas,and geochemical profiles

There is considerable interest in the use of thick argillaceous geologic formations to contain nuclear waste. Here, we show that diffusion can be the controlling transport process in these formations and diffusional time scales for δ¹⁸O and δ²H in water, dissolved He, and Cl transport in shale‐dominated aquitards are typically over 10⁶ years, well exceeding the regulatory requirements for isolation in most countries. Our scientific understanding of diffusive solute transport processes through argillaceous formations would benefit from the application of additional isotopic tracers (e.g., using new ⁴He sampling technology), multidimensional diffusive‐dispersive modeling of groundwater flow and diffusive‐dispersive solute transport over long geologic time scales, and an improved understanding of spatial heterogeneity as well as time‐dependent changes in the subsurface conditions and properties of argillaceous formations in response to events such as glaciation. Based on our current isotopic and geochemical understanding of transport, we argue that argillaceous formations can provide favorable long‐term conditions for isolating nuclear wastes.     

Fluid mapping in deeply buried Ordovician paleokarst reservoirs in the Tarim Basin,western China

The storage spaces within deeply buried Ordovician paleokarst reservoirs in the Tarim Basin are mostly secondary and characterized by strong heterogeneity and some degree of anisotropy. The types of fluids that fill the spaces within these reservoirs are of great importance for hydrocarbon exploration and exploitation. However, fluid identification from seismic data is often controversial in this area because the seismic velocity for this particular reservoir could be significantly influenced by many factors, including pore shapes, porosity, fluid types, and mineral contents. In this study, we employ the differential effective medium‐Gassmann rock physics model to interpret and discuss the characteristics of conventional karstic carbonate reservoirs in the Tarim Basin that are filled with different fluids (oil, gas, and water) using logging data and thus objectively build corresponding fluid identification criteria. These criteria are subsequently evaluated by amplitude versus offset (AVO) forward analysis based on typical logging data and further applied to ascertain the reservoir fluid types in two different areas in the Tarim Basin based on prestack inversion results. For conventional carbonate reservoirs, gas can be distinguished from heavy oil and water, but heavy oil and water are broadly similar on seismic data. For condensate carbonate reservoirs, water can be differentiated from light oil (i.e., condensates) and gas, but light oil and gas demonstrate substantial similarities in terms of their seismic responses. The predicted fluid results are in good agreement with the results of drilling and oil testing. In particular, modeling the seismically resolvable reservoirs in the carbonate strata in the Tarim Basin, which have needle‐ and sphere‐shaped storage spaces (pore aspect ratio > 0.3) and clay content that is lower than 5%, indicates that fluid properties could be properly evaluated if the porosity is larger than 5% for conventional carbonate reservoirs and >7% for condensate carbonate reservoirs.     

A phosphatic stromatolite (Ilicta cf. composita Sidorov) from the Middle Cambrian,northern Australia

Phosphatic stromatolites from the early Middle Cambrian (Ordian) of the Georgina Basin are described and identified as Ilicta cf. composita Sidorov. Based on Öpik's interpretation of the early Middle Cambrian, the age of the Georgina Basin specimens is similar to that of the type specimens described from the late Early Cambrian of Eastern Siberia. Phosphatic stromatolites occur at the base of dolomitized and partially silicified bioherms up to 4 m thick. The phosphatic forms overlie impermeable, cemented pavement surfaces which were covered by stratiform stromatolites from which rose columnar forms up to 5 cm in height. The stromatolites were phosphatized by penecontemporaneous diagenetic reactions that took place just below the sediment water interface and above the impermeable substrates.     

Numerical model of pore‐pressure diffusion associated with the initiation of the 2010–2011 Guy–Greenbrier,Arkansas earthquakes

We model pore‐pressure diffusion caused by pressurized waste‐fluid injection at two nearby wells and then compare the buildup of pressure with the observed initiation and migration of earthquakes during the early part of the 2010–2011 Guy–Greenbrier earthquake swarm. Pore‐pressure diffusion is calculated using MODFLOW 2005 that allows the actual injection histories (volume/day) at the two wells to diffuse through a fractured and faulted 3D aquifer system representing the eastern Arkoma basin. The aquifer system is calibrated using the observed water‐level recovery following well shut‐in at three wells. We estimate that the hydraulic conductivities of the Boone Formation and Arbuckle Group are 2.2 × 10^?2 and 2.03 × 10^?3 m day^?1, respectively, with a hydraulic conductivity of 1.92 × 10^?2 m day^?1 in the Hunton Group when considering 1.72 × 10^?3 m day^?1 in the Chattanooga Shale. Based on the simulated pressure field, injection near the relatively conductive Enders and Guy–Greenbrier faults (that hydraulically connect the Arbuckle Group with the underlying basement) permits pressure diffusion into the crystalline basement, but the effective radius of influence is limited in depth by the vertical anisotropy of the hydraulic diffusivity. Comparing spatial/temporal changes in the simulated pore‐pressure field to the observed seismicity suggests that minimum pore‐pressure changes of approximately 0.009 and 0.035 MPa are sufficient to initiate seismic activity within the basement and sedimentary sections of the Guy–Greenbrier fault, respectively. Further, the migration of a second front of seismicity appears to follow the approximately 0.012 MPa and 0.055 MPa pore‐pressure fronts within the basement and sedimentary sections, respectively.     

Fluid effect on hydraulic fracture propagation behavior: a comparison between water and supercritical CO2‐like fluid

The initiation of hydraulic fractures during fluid injection in deep formations can be either engineered or induced unintentionally. Upon injection of CO₂, the pore fluids in deep formations can be changed from oil/saline water to CO₂ or CO₂ dominated. The type of fluid is important not only because the fluid must fracture the rock, but also because rocks saturated with different pore fluids behave differently. We investigated the influence of fluid properties on fracture propagation behavior by using the cohesive zone model in conjunction with a poroelasticity model. Simulation results indicate that the pore pressure fields are very different for different pore fluids even when the initial field conditions and injection schemes (rate and time) are kept the same. Low viscosity fluids with properties of supercritical CO₂ will create relatively thin and much shorter fractures in comparison with fluids exhibiting properties of water under similar injection schemes. Two significant times are recognized during fracture propagation: the time at which a crack ceases opening and the later time point at which a crack ceases propagating. These times are very different for different fluids. Both fluid compressibility and viscosity influence fracture propagation, with viscosity being the more important property. Viscosity can greatly affect hydraulic conductivity and the leak‐off coefficient. This analysis assumes the in‐situ pore fluid and injected fluid are the same and the pore space is 100% saturated by that fluid at the beginning of the simulation.     

Exploring the potential linkages between oil‐field brine reinjection,crystalline basement permeability,and triggered seismicity for the Dagger Draw Oil field,southeastern New Mexico,USA, using hydrologic modeling

We used hydrologic models to explore the potential linkages between oil‐field brine reinjection and increases in earthquake frequency (up to M_d 3.26) in southeastern New Mexico and to assess different injection management scenarios aimed at reducing the risk of triggered seismicity. Our analysis focuses on saline water reinjection into the basal Ellenburger Group beneath the Dagger Draw Oil field, Permian Basin. Increased seismic frequency (>M_d 2) began in 2001, 5 years after peak injection, at an average depth of 11 km within the basement 15 km to the west of the reinjection wells. We considered several scenarios including assigning an effective or bulk permeability value to the crystalline basement, including a conductive fault zone surrounded by tighter crystalline basement rocks, and allowing permeability to decay with depth. We initially adopted a 7 m (0.07 MPa) head increase as the threshold for triggered seismicity. Only two scenarios produced excess heads of 7m five years after peak injection. In the first, a hydraulic diffusivity of 0.1 m² s^?1 was assigned to the crystalline basement. In the second, a hydraulic diffusivity of 0.3 m² s^?1 was assigned to a conductive fault zone. If we had considered a wider range of threshold excess heads to be between 1 and 60 m, then the range of acceptable hydraulic diffusivities would have increased (between 0.1–0.01 m² s^?1 and 1–0.1 m² s^?1 for the bulk and fault zone scenarios, respectively). A permeability–depth decay model would have also satisfied the 5‐year time lag criterion. We also tested several injection management scenarios including redistributing injection volumes between various wells and lowering the total volume of injected fluids. Scenarios that reduced computed excess heads by over 50% within the crystalline basement resulted from reducing the total volume of reinjected fluids by a factor of 2 or more.     

Cementation and the hydromechanical behavior of siliciclastic aquifers and reservoirs

Progressive cementation and lithification significantly influence the mechanical and hydrologic properties of granular porous media through elastic stiffening and permeability reduction. We use published data that quantify the effect of grain‐bridging cement distribution in granular porous media at the grain scale to investigate the influence of variable cement content on the competing roles of hydrologic and mechanical effects on fluid flow and deformation at the reservoir scale. The impact of quartz overgrowths in natural samples was quantified using a bond‐to‐grain ratio, allowing a geologically meaningful interpretation of percent cement in conceptual models of quartz cementation. An increase in the bond‐to‐grain ratio from 1 to 2.2 (~1–15% cement by volume) results in a 1.4‐fold increase in Young's modulus and an ~1000‐fold decrease in permeability. The hydromechanical properties of a suite of variably cemented natural samples are used as input into two‐dimensional, kilometre‐scale, axially symmetric poroelastic models of an isotropic confined aquifer. Models isolating the hydrologic and mechanical effects of cementation indicate that the hydrologic properties dominate the overall mechanical response, controlling both the volume and magnitude of deformation. Incorporation of changes in hydrologic properties due to cementation is therefore essential to capturing the first‐order physics of coupled aquifer behavior.     

Abnormally pressured beds as barriers to diffusive solute transport in sedimentary basins

Diffusion can drive significant solute transport over millions of years, but ancient brines and large salinity gradients are still observed in deep sedimentary basins. Fluid flow within abnormally pressured beds may prevent diffusive transfer over geologically significant periods, if the abnormally pressured bed is surrounded by normally pressured beds. Analytic solutions based on sediment loading and unloading demonstrate that this effect should be considered in beds with a compressibility exceeding 10^?8 Pa^?1, with a thickness of 100 m or more, or a sedimentation rate exceeding 10^?5 m year^?1. Conditions favourable for our model of abnormally pressured beds appear common in sedimentary basins. Large salinity gradients associated with clay beds have previously been attributed to membrane effects, but flow patterns associated with abnormally pressured beds appear more robust in the presence of heterogeneity and discontinuities than membrane effects. Calculations suggest that thick underpressured shales in the Alberta basin may have allowed ancient evaporatively concentrated brines to be preserved beneath a vigorous topography‐driven flow system over the last 60 My. In the Illinois basin, drained overpressured beds may have limited solute transport across the New Albany shale until approximately 250 Ma. It is unlikely, however, that overpressures could have persisted long enough to explain concentration gradients observed in the modern basin. These gradients may instead reflect relatively recent halite dissolution above the New Albany shale.     

Pliocene sand injectites from a submarine lobe fringe during hydrocarbon migration and salt diapirism: a seismic example from the Lower Congo Basin

Large‐scale conical and saucer‐shaped sand injectites have been identified in the Upper Miocene sediments of the Lower Congo Basin. These structures are evidenced on the 3D high‐resolution seismic data at about 600 ms TWT (two‐way traveltime) beneath the seabed. The conical and saucer‐shaped anomalies range from 20 to 80 m in height, 50 to 300 m in diameter, and 10 to 20 ms TWT in thickness. They are located within a sedimentary interval of about 100 m in thickness and are aligned over 20 km in dip direction (NE‐SW), above the NW margin of an underlying Upper Miocene submarine fan. We have interpreted the conical and saucer‐shaped anomalies as upward‐emplaced sand injectites sourced from the Upper Miocene fan because of their discordant character, the postsedimentary uplifting of the sediments overlying the cones and saucer‐shaped bodies, the alignment with the lateral fringe of the Upper Miocene submarine fan, and the geological context. Sand injection dates from the Miocene–Pliocene transition (approximately 5.3 Ma). The prerequisite overpressure to the sand injection process may be due to the buoyancy effect of hydrocarbons accumulated in the margins of the fan. Additionally, overpressure could have been enhanced by the lateral transfer of fluids operating in the inclined margins of the lobe. The short duration of sand injection and the presence of many sandstone intrusions suggested that the process of injection was triggered by an event, likely due to a nearby fault displacement related to diapiric movements. This is the first time that sand injectites of seismic scale have been described from the Lower Congo Basin. The localized nature of these injectites has led to a change in the migration path of fluids through the sedimentary cover. Consequently, the sand intrusions are both evidence and vectors of fluid migration within the basin fill.