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.     

Measurements of gas permeability and diffusivity of tight reservoir rocks: different approaches and their applications

Permeability and diffusivity are critical parameters of tight reservoir rocks that determine their viability for commercial development. Current methods for measuring permeability and/or diffusivity may lead to erroneous results when applied to very tight rocks including gas shales, coal, and tight gas sands, as well as rocks considered as seals for nuclear waste repositories and strata for geological sequestration of CO₂. The use of He as routinely applied to measure porosity, permeability, and diffusivity may result in non-systematic errors because of the molecular sieving effect of the fine pore structure to larger molecules such as reservoir gases. Utilizing gases with larger adsorption potentials than He, such as N₂, and including all reservoir gases to measure porosity or permeability of rocks with high surface area is a viable alternative, but requires correcting for adsorption in the analyses. This study expands several approaches to measure permeability and diffusivity with considerations for gas adsorption, which has not been explicitly considered in previous studies. We present new models that explicitly correct for adsorption during pulse-decay measurements of core under reservoir conditions, as well as on crushed samples used to approximate permeability or diffusivity. We also present a method to determine permeability or diffusivity from on-site drill-core desorption test data as carried out to determine gas in place in coals or gas shales. Our new approach utilizes late-time data from experimental pressure-decay tests, which we show to be more reliable and theoretically (and practically) accurate than the early-time approach commonly used to estimate gas-transport properties.     

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.     

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.     

Permeability of the Mercia Mudstone: suitability as caprock to carbon capture and storage sites

The Upper Triassic Mercia Mudstone is the caprock to potential carbon capture and storage (CCS) sites in porous and permeable Lower Triassic Sherwood Sandstone reservoirs and aquifers in the UK (primarily offshore). This study presents direct measurements of vertical (k_v) and horizontal (k_h) permeability of core samples from the Mercia Mudstone across a range of effective stress conditions to test their caprock quality and to assess how they will respond to changing effective stress conditions that may occur during CO₂ injection and storage. The Mercia samples analysed were either clay‐rich (muddy) siltstones or relatively clean siltstones cemented by carbonate and gypsum. Porosity is fairly uniform (between 7.4 and 10.7%). Porosity is low either due to abundant depositional illite or abundant diagenetic carbonate and gypsum cements. Permeability values are as low as 10^?20 m² (10nD), and therefore, the Mercia has high sealing capacity. These rocks have similar horizontal and vertical permeabilities with the highest k_h/k_v ratio of 2.03 but an upscaled k_h/k_v ratio is 39, using the arithmetic mean of k_h and the harmonic mean of k_v. Permeability is inversely related to the illite clay content; the most clay‐rich (illite‐rich) samples represent very good caprock quality; the cleaner Mercia Mudstone samples, with pore‐filling carbonate and gypsum cements, represent fair to good caprock quality. Pressure sensitivity of permeability increases with increasing clay mineral content. As pore pressure increases during CO₂ injection, the permeability of the most clay‐rich rocks will increase more than carbonate‐ and gypsum‐rich rocks, thus decreasing permeability heterogeneity. The best quality Mercia Mudstone caprock is probably not geochemically sensitive to CO₂ injection as illite, the cause of the lowest permeability, is relatively stable in the presence of CO₂–water mixtures.     

Reanalysis of in situ permeability measurements in the Barbados décollement

A cased and sealed borehole in the Northern Barbados accretionary complex was the site of the first attempts to measure permeability in situ along a plate boundary décollement. Three separate efforts at Hole 949C yielded permeability estimates for the décollement spanning four orders of magnitude. An analysis of problems encountered during installation of the casing and seals provides insights into how the borehole conditions may have led to the wide range of results. During the installation, sediments from the surrounding formation repeatedly intruded into the borehole and casing. Stress analysis shows that the weak sediments were deforming plastically and the radial and tangential stresses around the borehole were significantly lower than lithostatic. This perturbed stress state may explain why the test pressure records showed indications of hydrofracture at pressures below lithostatic, and permeabilities rose rapidly as the estimated effective stress dropped below 0.8 MPa. Even after the borehole was sealed, the plastic deformation of the formation and relatively large gap of the wire wrapped screen allowed sediment to flow into the casing. Force equilibrium calculations predict sediment would have filled the borehole to 10 cm above the top of the screen by the time slug tests were conducted 1.5 years after the borehole was sealed. Reanalysis of the slug test results with these conditions yields several orders of magnitude higher permeability estimates than the original analysis which assumed an open casing. Overall the results based on only the tests with no sign of hydrofracture yield a permeability range of 10^?14–10^?15 m² and a rate of increase in permeability with decreasing effective stress consistent with laboratory tests on samples from the décollement zone.     

Investigation of coupled hydraulic–geomechanical processes at the KTB site: pressure‐dependent characteristics of a long‐term pump test and elastic interpretation using a geomechanical facies model

The German Continental Deep Drilling Program comprising a pilot borehole down to 4000 m and a main borehole down to 9101 m in southeast Germany (KTB) is continuing to provide a unique opportunity for the identification of important factors and processes in deep‐seated fluid and energy transfer. In situ stress conditions significantly impact flow, transport and exchange characteristics of fracture networks that dominate the permeability of crystalline reservoir rocks. In this paper, several scales of information are combined to present a fully three‐dimensional hydraulic finite element model of the principal KTB fault zones, and linked to a geomechanical model describing the alteration of the hydraulic parameters with stress changes caused by fluid extraction. The concept of geomechanical facies is introduced to define and characterize architectural elements in the subsurface system. Evaluation of a long‐term pump test in the KTB pilot hole, June 2002–July 2003, coupled with a geomechanical model gives an insight into some of the elastic and nonelastic processes controlling hydraulic transport in the basement rocks. Trends in the decline of the permeability and the degree of storage in the system could only partially be explained by elastic processes, clearly indicating the importance of nonelastic processes. A number of inelastic processes are suggested as areas for further research.     

How should permeability be measured in fine‐grained lithologies? Evidence from the chalk

Two chalk data sets from the Central North Sea (UK/Norway and Denmark) with a similar lithological classification and porosity values (5–20%) have a difference in permeability of up to three orders of magnitude. The method of measuring permeability was different for the two data sets: samples from UK/Norway were measured by transient pulse decay (TPD), while the Danish samples were measured by routine core analysis. Petrological and petrophysical characterization of samples from the two data sets have revealed that all samples display a similar range of rock properties; the differences are not due to regional facies variations. It is likely that the low permeability values reported by TPD have more validity than routine core analyses in measuring lower porosity and permeability chalk (5–20% porosity, <0.01 mD). The fact that large sections of North Sea chalk potentially have much lower permeability than previously reported has widespread implications for petroleum migration and entrapment, and overpressure generation.     

Geological controls on regional transmissivity anisotropy

A variety of data indicate that the Carbonate aquifer in southern Manitoba is a heterogeneous and anisotropic aquifer wherein groundwater flow follows preferred flow path networks. Specific capacity tests show that aquifer transmissivity can vary by up to four orders of magnitude within 1 km. Geostatistical analysis reveals a strong anisotropy in the transmissivity field, with better spatial continuity in NE–SW and NW–SE directions, coincident with the dominant orientations of fractures observed in bedrock exposures. However, discrepancies between the orientation of highest fracture density and best transmissivity continuity suggest that either additional geological factors control the preferred flow network or there is a biased representation of the fracture pattern because all direct fracture observations came from the northern part of the study area. In an effort to investigate whether the geographically biased fracture data set represents the fracture pattern for the whole region, Landsat images and digital elevation maps were processed to extract linear features that may indicate subsurface fracture zones in areas where bedrock is covered by glacial sediments. The results suggest a consistent fracture pattern throughout the study area, indicating that the two observed fracture groups might have gone through different processes in terms of permeability development. Alteration by mineral cementation and dissolution along fracture surfaces may have preferentially improved the fracture permeability in one orientation, while reducing it in the other. The in situ stress field is also believed to play a major role in the preferred regional flow network. This paper discusses the evidence for the preferred flow path network and possible geological factors controlling aquifer anisotropy in this region.     

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.     

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.     

Combining finite element and finite volume methods for efficient multiphase flow simulations in highly heterogeneous and structurally complex geologic media

The permeability of the Earth's crust commonly varies over many orders of magnitude. Flow velocity can range over several orders of magnitude in structures of interest that vary in scale from centimeters to kilometers. To accurately and efficiently model multiphase flow in geologic media, we introduce a fully conservative node‐centered finite volume method coupled with a Galerkin finite element method on an unstructured triangular grid with a complementary finite volume subgrid. The effectiveness of this approach is demonstrated by comparison with traditional solution methods and by multiphase flow simulations for heterogeneous permeability fields including complex geometries that produce transport parameters and lengths scales varying over four orders of magnitude.     

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.     

Structural controls on hydrothermal flow in a segmented rift system, Taupo Volcanic Zone, New Zealand

Vigorous hydrothermal convection transfers 10 times the average continental heat flow through the central Taupo Volcanic Zone (TVZ), a region of active extension (approximately 8 mm year^?1) and productive rhyolitic volcanism. Over 20 high‐temperature (>250°C) geothermal fields occur within Quaternary pyroclastic basins, with convective circulation to depths of 7–8 km presumably extending through basement rocks. Parallel‐striking normal faults, fractures and dikes dissect the convective regime, interacting with fluids to either enhance or restrict flow according to the relative permeability of structure and host rock. In the basement, high bulk permeability is maintained by focussed flow through faults and associated fractures well oriented for reactivation in the prevailing stress field. In contrast, distributed flow through fault‐bounded compartments prevails within Quaternary basins, masking any signal of deeper structural control. Exceptions occur where more competent rocks are exposed at the surface. As in narrow magmatic rifts elsewhere, the extensional fabric is partitioned into discrete rift segments linked along strike by accommodation zones. Eighty per cent of TVZ geothermal fields correlate spatially with rift architecture, with 60% located in accommodation zones. We suggest that segmented rift fabrics generate bulk permeability anisotropy that is to some extent predictable, with rift segments characterized by enhanced axial flow, and accommodation zones characterized by locally enhanced vertical permeability that is tectonically maintained. This provides a plausible explanation for the common occurrence of geothermal fields within accommodation zones and their notable absence within densely faulted rift segments. Maintenance of structural permeability in zones of active hydrothermal precipitation necessarily requires repeated brittle failure. Geothermal plumes therefore exploit tectonically maintained permeability within accommodation zones, with rift segments functioning mostly as drawdown regions. The influence of rift architecture on flow paths has important implications for geothermal extraction and epithermal mineral exploration within the TVZ and other structurally segmented hydrothermal systems, both active and extinct.     

The effect of deformation on permeability development in anhydrite and implications for caprock integrity during geological storage of CO2

Geological storage of CO₂ in depleted oil and gas reservoirs is one of the most promising options to reduce atmospheric CO₂ concentrations. Of great importance to CO₂ mitigation strategies is maintaining caprock integrity. Worldwide many current injection sites and potential storage sites are overlain by anhydrite‐bearing seal formations. However, little is known about the magnitude of the permeability change accompanying dilatation and failure of anhydrite under reservoir conditions. To this extent, we have performed triaxial compression experiments together with argon gas permeability measurements on Zechstein anhydrite, which caps many potential CO₂ storage sites in the Netherlands. Our experiments were performed at room temperature at confining pressures of 3.5–25 MPa. We observed a transition from brittle to semi‐brittle behaviour over the experimental range, and peak strength could be described by a Mogi‐type failure envelope. Dynamic permeability measurements showed a change from ‘impermeable’ (<10^?21 m²) to permeable (10^?16 to 10^?19 m²) as a result of mechanical damage. The onset of measurable permeability was associated with an increase in the rate of dilatation at low pressures (3.5–5 MPa), and with the turning point from compaction to dilatation in the volumetric versus axial strain curve at higher pressures (10–25 MPa). Sample permeability was largely controlled by the permeability of the shear faults developed. Static, postfailure permeability decreased with increasing effective mean stress. Our results demonstrated that caprock integrity will not be compromised by mechanical damage and permeability development. Geofluids (2010) 10 , 369–387     

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.     

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.     

Chloride ion concentrations during the compression of rocks to extract pore water

Pore water needs to be extracted from rocks with low permeabilities to allow the major ion concentrations in the pore water to be estimated. Compressing a rock is the most widely used method of extracting the pore water. However, ion concentrations have been found to change during compression in previous studies, and the mechanisms involved in such ion concentration changes have not yet been fully assessed. In this study, two natural rocks and four artificially prepared samples were compressed, and changes in the chloride ion (Cl^?) concentrations as the compression pressure increased were investigated. Mechanisms that could have caused the changes observed were then assessed. The Cl^? concentrations in squeezed water decreased as the pressure increased if the sample contained a significant amount of smectite. The strong dependence of Cl^? concentration on the amount of smectite indicated that smectite played an important role in decreasing the Cl^? concentration. The dilution of the pore water with interlayer water from the smectite appeared to be the dominant mechanism involved in the decrease in Cl^? concentration found in a Kunigel‐V1 sample, because dilution of the pore water with interlayer water quantitatively explained the decrease in the Cl^? concentration. The filter effect caused by the anion exclusion effect did not appear to be a dominant mechanisms in our case. However, Cl^? concentration decrease found in natural rocks could not be fully explained by dilution with interlayer water, so other mechanisms must be involved the phenomenon in natural rocks.     

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.     

Massive dolomitization of a Messinian reef in the Great Bahama Bank: a numerical modelling evaluation of Kohout geothermal convection

The hypothesis that Kohout thermal convection may have induced the massive dolomitization of the 60 m thick lowest more reefal unit in well Unda [top of Great Bahama Bank (GBB)] is evaluated through numerical modelling. A two‐dimensional (2‐D) section, including lithological and petrophysical data, together with datings for the sediments of the GBB, was used in the basin model TEMISPACK to reconstruct the history of the whole platform, with a focus on the reef unit. Simulations showed that during high sea‐level periods, Kohout convection is a valid mechanism in the settings of the GBB, although the convection cell remains flat in most cases because of high permeability anisotropy. This mechanism induces rapid fluid flow in the superficial as well as in the deeper parts of the platform, with velocities of at least two orders of magnitude higher than with compaction alone. Lithology appears as a strong control of fluid circulations at the margin scale through the permeability anisotropy, for which a critical value lies between values of 10 and 100. The reefal unit in Unda is part of a larger area determined by the lithologic distribution, in which flow velocities are significantly higher than in the rest of the platform. These velocities are high enough to bring the magnesium necessary to precipitate the observed amounts of dolomite, within durations in agreement with the available time of post‐reef deposition high sea level(s). However, neither fluid flow pattern nor flow velocities are able to explain the preferential massive dolomitization of the lower reef unit and the complete absence of dolomite in the upper one.