GEOLOGY Deformation-assisted fluid percolation in rock salt Soheil Ghanbarzadeh, 1 Marc A. Hesse, 2,3 * Maša Prodanović, 1 James E. Gardner 2 Deep geological storage sites for nuclear waste are commonly located in rock salt to ensure hydrological isolation from groundwater.The low permeability of static rock salt is due to a percolation threshold. However, deformation may be able to overcome this threshold and allow fluid flow. We confirm the percolation threshold in static experiments on synthetic salt samples with x-ray microtomography. We then analyze wells penetrating salt deposits in the Gulf of Mexico. The observed hydrocarbon distributions in rock salt require that percolation occurred at porosities considerably below the static threshold due to deformation-assisted percolation. Therefore, the design of nuclear waste repositories in salt should guard against deformation-driven fluid percolation. In general, static percolation thresholds may not always limit fluid flow in deforming environments. R ock salt in sedimentary basins has long been considered to be impermeable and provides a seal for hydrocarbon accumu- lations in geological structures (1, 2). The low permeability of rock salt also has the potential to isolate nuclear waste from ambient groundwater and may provide a suitable deep geological waste repository (3, 4). This option is currently being reconsidered in the United States after the closure of the Yucca Mountain repository in Nevada (3). However, field observations of oil- impregnated rock salt (5), geochemical evidence for the replacement of the in situ brines (6), and the drainage of brine from mining-induced frac- tures and dilatant microcracking (3, 7) demon- strate that the permeability of natural rock salt may not be negligible. Brine-filled pore networks in rock salt ap- proach textural equilibrium due to fast reaction kinetics of salt dissolution and reprecipitation (8). Percolation in these networks is controlled by the dihedral angle q at the solid-solid-liquid triple junctions q ¼ 2cos −1 ½g ss =ð2g sl Þ ð1Þ where g ss and g sl are the solid-solid and solid- liquid surface energies (9–12). The dihedral angle is therefore a thermodynamic property that changes with pressure P and temperature T. The static pore-scale theory shows that texturally equilibrated pore networks percolate at any po- rosity if q ≤ 60°, whereas a finite porosity is re- quired for percolation if q > 60° (10–12). The experimentally measured q in salt-brine systems decreases with both increasing P and T (Fig. 1), suggesting that fluids at shallow depth must overcome a percolation threshold, whereas fluids at greater depth are likely to percolate at any porosity. The PT trajectory of multiple petro- leum wells in the Gulf of Mexico crosses this transition and therefore provides an opportunity to test the static pore-scale theory in a realistic field setting. We confirm the static pore-scale theory in undrained laboratory experiments on synthetic SCIENCE sciencemag.org 27 NOVEMBER 2015 • VOL 350 ISSUE 6264 1069 1 Department of Petroleum and Geosystems Engineering, The University of Texas at Austin, 200 East Dean Keeton Street, Austin, TX 78712, USA. 2 Department of Geological Sciences, The University of Texas at Austin, 1 University Station, Austin, TX 78712, USA. 3 Institute for Computational Engineering and Sciences, The University of Texas at Austin, 201 East 24th Street, Austin, TX 78712, USA. *Corresponding author. E-mail: [email protected]Fig. 1. Brine percolation in rock salt. PT trajecto- ries of multiple subsalt petroleum wells are shown together with experimentally measured dihedral angles q for the salt-brine system (8). The static theory predicts that fluid must overcome a perco- lation threshold in the gray area, whereas fluids are predicted to percolate at any porosity in the white area. The light gray area highlights the transition zone, 60° < q < 65°, between percolating and disconnected pore space (8). The segment of each well that is located within the salt has a lower geothermal gradient due to the high conduc- tivity of salt and is shown as a dashed line. The depth axis is only for illustration and assumes an overburden with constant density, r = 2300 kg/m 3 . RESEARCH | REPORTS on October 8, 2020 http://science.sciencemag.org/ Downloaded from
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GEOLOGY
Deformation-assisted fluidpercolation in rock saltSoheil Ghanbarzadeh,1 Marc A. Hesse,2,3* Maša Prodanović,1 James E. Gardner2
Deep geological storage sites for nuclear waste are commonly located in rock salt toensure hydrological isolation from groundwater. The low permeability of static rocksalt is due to a percolation threshold. However, deformation may be able to overcomethis threshold and allow fluid flow. We confirm the percolation threshold in staticexperiments on synthetic salt samples with x-ray microtomography. We then analyzewells penetrating salt deposits in the Gulf of Mexico. The observed hydrocarbondistributions in rock salt require that percolation occurred at porosities considerablybelow the static threshold due to deformation-assisted percolation. Therefore, thedesign of nuclear waste repositories in salt should guard against deformation-drivenfluid percolation. In general, static percolation thresholds may not always limit fluidflow in deforming environments.
Rock salt in sedimentary basins has longbeen considered to be impermeable andprovides a seal for hydrocarbon accumu-lations in geological structures (1, 2). Thelow permeability of rock salt also has the
potential to isolate nuclear waste from ambientgroundwater and may provide a suitable deepgeological waste repository (3, 4). This option iscurrently being reconsidered in the United Statesafter the closure of the YuccaMountain repository
in Nevada (3). However, field observations of oil-impregnated rock salt (5), geochemical evidencefor the replacement of the in situ brines (6), andthe drainage of brine from mining-induced frac-tures and dilatant microcracking (3, 7) demon-strate that the permeability of natural rock saltmay not be negligible.Brine-filled pore networks in rock salt ap-
proach textural equilibrium due to fast reactionkinetics of salt dissolution and reprecipitation
(8). Percolation in these networks is controlledby the dihedral angle q at the solid-solid-liquidtriple junctions
q ¼ 2cos−1½gss=ð2gslÞ� ð1Þwhere gss and gsl are the solid-solid and solid-liquid surface energies (9–12). The dihedral angleis therefore a thermodynamic property thatchanges with pressure P and temperature T. Thestatic pore-scale theory shows that texturallyequilibrated pore networks percolate at any po-rosity if q ≤ 60°, whereas a finite porosity is re-quired for percolation if q > 60° (10–12).The experimentally measured q in salt-brine
systems decreases with both increasing P and T(Fig. 1), suggesting that fluids at shallow depthmust overcome a percolation threshold, whereasfluids at greater depth are likely to percolate atany porosity. The PT trajectory of multiple petro-leum wells in the Gulf of Mexico crosses thistransition and therefore provides an opportunityto test the static pore-scale theory in a realisticfield setting.We confirm the static pore-scale theory in
1Department of Petroleum and Geosystems Engineering, TheUniversity of Texas at Austin, 200 East Dean Keeton Street,Austin, TX 78712, USA. 2Department of Geological Sciences, TheUniversity of Texas at Austin, 1 University Station, Austin, TX78712, USA. 3Institute for Computational Engineering andSciences, The University of Texas at Austin, 201 East 24thStreet, Austin, TX 78712, USA.*Corresponding author. E-mail: [email protected]
Fig. 1. Brine percolation in rock salt. PT trajecto-ries of multiple subsalt petroleum wells are showntogether with experimentally measured dihedralangles q for the salt-brine system (8). The statictheory predicts that fluid must overcome a perco-lation threshold in the gray area, whereas fluidsare predicted to percolate at any porosity in thewhite area. The light gray area highlights thetransition zone, 60° < q < 65°, between percolatingand disconnected pore space (8). The segmentof each well that is located within the salt has alower geothermal gradient due to the high conduc-tivity of salt and is shown as a dashed line. Thedepth axis is only for illustration and assumes anoverburden with constant density, r = 2300 kg/m3.
salt samples that have been imaged with non-destructive x-ray microtomography after quench-ing to ambient conditions (13). We present theresults of two representative experiments (Fig.2) performed at P = 20 MPa and T = 100°C(Exp-I) and P = 100 MPa and T = 275°C (Exp-II).The three-dimensional (3D) reconstruction (Fig.2, A and B) and medial axis representation ofthe pore space (Fig. 2, C and D) show that thebrine network is disconnected in Exp-I and isconnected in Exp-II. This is confirmed by sta-tistical analysis of the coordination number dis-tributions that show that almost all nodes inExp-I have coordination number 1, whereas thecoordination numbers of 3 and 4 are most abun-dant in Exp-II (fig. S4). The distribution of theapparent dihedral angles has amedian of 67 ± 5°for Exp-I and 52 ± 6° for Exp-II (Fig. 2E). Dis-tributions with a single narrow peak, as well assimilarity to previously reported values of dihe-dral angle (8), indicate that the experiments areapproaching textural equilibrium. Comparisonof experiments with the regime diagram forfluid percolation show that static pore-scale theorysuccessfully predicts the connectivity of the porespace (Fig. 2F). These experimental results con-firm the first-order control of the dihedral angleon brine percolation and serve as a baseline forthe field observations of fluid distributions indeformed rock salt.
Commercial interest in the large hydrocarbonaccumulations below extensive bodies of alloch-thonous salt in the deepwater Gulf of Mexicoprovides an opportunity to test the static pore-scale theory in slowly moving natural rock salt.We studied field data from the salt section of48 wells crossing the predicted transition zonefrom disconnected to percolating pore space(Fig. 1) to constrain the brine and hydrocarbonconnectivity. Typically, no intact core is recov-ered from the salt section of wells, and theavailable data sets consist of wireline well logsand mud logs (13). Wireline well logs, obtainedby lowering a measurement tool into the well,characterize different properties of the forma-tion rock and fluids (Fig. 3, A and B). Mud logs,which record the hydrocarbon gas content andobservations from the drill cuttings brought tothe surface, provide direct constraints on thepresence of hydrocarbons in salt (Fig. 3, C to E).Hydrocarbon signs reported in mud logs includefluorescence, oil staining, oil cut, and dead oilembedded in the salt.We chose only those salt sections for analysis
that were free of other rock fragments, as indi-cated by low values of naturally occurring gammaradiation (Fig. 3A). In contrast to the uniformgamma-ray signature, all other logs (Fig. 3, B toE) show a distinct change in the bottom thirdof the salt. The very high electrical resistivity in
the upper two-thirds of the salt section impliesthat the conductive brine is not connected (Fig.3B) (14). In this region, the porosity calculatedfrom Archie’s law is below 0.4% (Fig. 2G) (13).The reduction of electrical resistivity by an or-der of magnitude in the bottom third suggeststhat brine is connected at porosities below 0.8%(Fig. 2G). The salt-brine dihedral angle inferredfrom the PT trajectory of the well (fig. S6) (13)drops below 60° in the bottom third of the salt(Fig. 3F), consistent with the static pore-scaletheory.In addition to a connected brine phase, the
total gas hydrocarbons and gas chromatographylogs indicate a substantial increase in the amountof natural gas in the lower third of the salt (Fig. 3,C and D). We observe this general pattern also inthe mud logs that contain no indications of hy-drocarbons in the top two-thirds but show mul-tiple signs of hydrocarbons in the bottom third(Fig. 3E). In the presence of brine, hydrocarbonsare the nonwetting phase, so that the texturalequilibration of the pore network occurs throughbrine-mediated dissolution and reprecipitationof the salt. The dihedral angle of the brine-saltsystem governs the connectivity of pore space,consistent with observations in wireline welllogs andmud logs. Once hydrocarbons overcomethe capillary entry pressure (5), they can enterthe salt in regions where the brine network is
Fig. 2. Pore networks in rock salt. Hydrostatic experiments on syntheticrock salt have been performed at P = 20 MPa and T = 100°C (Exp-I) and P =100 MPa and T = 275°C (Exp-II). (A and B) 3D reconstruction of the porenetwork at textural equilibrium; all edges of the 3D volumes correspond to660 mm. (C and D) The skeletonized pore network extracted from thereconstructed 3D volume; colored according to local pore-space-inscribedradius, with warmer colors indicating larger radius. (E) Distribution of ap-
parent dihedral angles in the experiments. (F) Exp-I and Exp-II in the qfspace regime diagram with the percolation threshold obtained from thestatic pore-scale theory (10, 12). Inserted images show the details of auto-mated dihedral angle extraction from 2D images (13).We report the medianvalue of dihedral angles and the estimated errors based on the 95% con-fidence interval. (G) Porosity of natural rock salt inferred from resistivity logs(Fig. 3B).
connected. Subsequent imbibition of the brinecan trap the hydrocarbons in the pore space(fig. S7). The presence of hydrocarbons there-fore indicates that a connected pore space existedduring the entry of the hydrocarbons into therock salt. This interpretation is consistent withprevious work reporting direct observations ofoil-stained salt cores recovered from conditionswhere q < 60° (5).High-quality resistivity logs (Fig. 3B) are only
available in twowells due to technical difficultiesand lack of commercial interest in the salt sec-tion of wells. Therefore, we rely on the logs thatdetect hydrocarbons to infer the connectivity ofthe brine in the remaining 46 wells. We groupspatially associated wells to look at the distri-bution of hydrocarbons in salt sections (Fig. 4).The abundance of hydrocarbons is affected bythe distance of the nearest hydrocarbon sourcefrom the bottom of the salt. For example, the firstoil source is more than 2000m below the base ofsalt in the wells of group WR13, justifying thesparsity of hydrocarbon signs.We converted the depth to dihedral angle
using available experimental data (Fig. 1 and fig.S6). All the wells that we considered show signsof connected pore space at depths where thedihedral angle is below 60°, except the shallowwells of group MC11. Using the two electrical re-sistivity logs and Archie’s law, we estimate thatthe porosity of these connected regions is lessthan 1% (Fig. 2G). This provides direct field evi-dence that dihedral angles below 60° allow thepercolation of texturally equilibrated pore net-works at porosities below the transport limit inmore typical porous media that originated asclastic sediments (15).Nonetheless, field data also show evidence
of percolating pore space at shallower depths,where the dihedral angle is substantially above60° (Fig. 4). Under these conditions, the poros-ity must increase above a threshold to allowpercolation. Static pore-scale theory requiresporosities between 2 and 3% to allow perco-lation at dihedral angles between 65° and 70°(Fig. 2F). However, none of the porosities in-ferred from the available resistivity logs ex-ceed 1%, and most are substantially lower (Fig.2G), which is consistent with direct measure-ments of rock salt porosity (16, 17). The ob-servation of percolating fluids at high dihedralangles and low porosities is not consistent withthe static theory.Viscous flow of rock salt due to the density
contrast with the surrounding sediments mayexplain the failure of the static pore-scale theoryto predict the percolation of pore space at highdihedral angles. At low effective mean stress,deformation-induced microcracking can leadto the formation of a percolating pore space (5).This microcracking-induced percolation is com-monly observed in the zone of disturbed rockaround openings in salt mines or nuclear wasterepositories and under high overpressures innature (3, 5). At the depth of petroleum wellsconsidered here, the effective mean stress is suf-ficient that deformation occurs in the compac-
tion regime, where existingmicrocracks close andheal (18, 19).However, deformation may induce perme-
ability even in the absence of microcracking.At high effective mean stress and in the presenceof small amounts of brine, the dislocation creepof salt is accompanied by fluid-assisted dyna-mic recrystallization and pressure solution creep(20–22). Both static and dynamic recrystalliza-tion are associated with transformation of theisolated grain-boundary fluid inclusions into grain-boundary fluid films (23, 24). The dynamic wet-ting of the grain boundaries and compactionhave been observed in deformation experimentsunder conditions where q ≈ 64° (22). This sug-gests that dynamic grain-boundary wetting in-duced fluid percolation and drainage at porositiesbelow the percolation threshold.These laboratory results must be extrapolated
to natural conditions using appropriate micro-physical models and suggest that fluid-assisteddynamic recrystallization becomes important atstrain rates below 10–10 s–1 (21). This is consistent
with the recrystallized microstructures and x-raymicrotomography of grain-boundary brine filmsin natural rock salt, as well as estimated naturalstrain rates between 10–15 and 10–11 s–1 (5, 25, 26).This confirms earlier suggestions that dynamicgrain-boundary wetting associated with grain-boundary migration is a plausible mechanismin natural rock salt.This conclusion is also supported by the
comparison of the relative magnitude of shearstresses, Ds, and the capillary pressure intro-duced by surface tension forces, Dp, given bycapillary number
Ca ¼ DsDp
¼ Ds2gsl=r
ð2Þ
where r is the mean radius of disconnectedpores. Microstructural evidence preserves re-cords of differential stresses up to 1 MPa insubhorizontal bedded salts (27) and 2 MPa insalt domes (5, 28). In comparison, the capillarypressure for r = 10–4m and gsl = 0.1 N/m is on the
Fig. 3. Petrophysical observations. Wireline well logs and mud logs data constraining the fluid dis-tribution and connectivity in the well GC8 from the deep water Gulf of Mexico (13). (A) Gamma-ray log,(B) electrical resistivity, (C) total hydrocarbons gas, (D) gas chromatography, (E) hydrocarbon signs(FL, fluorescence; OS, oil stain; DO, dead oil; and OC, oil cut) in mud logs, and (F) the dihedral angleinferred from experimental data (Fig. 1). Shading around each curve shows themeasurement error andaverage fluctuations in data. The gray background corresponds to shaded areas in the experimentaldata (Fig. 1).
order of 103 Pa (29). Therefore, Ca ≈ 103 and theshear stresses in rock salt may exceed capillarypressures and hence facilitate deformation-assisted percolation. This provides an explana-tion for the penetration of hydrocarbons intoshallow regions of the salt, where q > 60° andporosity is below the static percolation thresh-old (Fig. 2G and Fig. 4).These field observations have implications for
ensuring hydrological isolation of nuclear wastein rock salt. At the relatively shallow depth typi-cally considered for geological storage, the di-hedral angle is between 65° and 72° and shouldprevent brine percolation in rock salt, based onstatic pore-scale theory and experiments. How-ever, field observations reported here show thatsuch moderate dihedral angles do not guaranteehydrological isolation in deformed rock salt.The deformation-assisted percolation observedin salt sections of petroleum wells is not asso-ciated with human-made excavations, suggest-ing that this mechanism is not limited to thevicinity of the repository site and the durationof room closure around the waste. Lower dif-ferential stresses recorded in shallow beddedrock salt suggest that it is more likely to providean impermeable barrier. However, tectonic forcesand excavations can result in high stresses inshallow cold salt. Therefore, it is important tocharacterize the salt microstructure of potentialrepositories to determine the stress history, stateof grain boundaries, and fluid distribution. Futurework should also constrain the permeability thatcan be generated by deformation-assisted perco-lation and its persistence.Beyond the direct application to salt-brine
systems, the field observations reported herealso provide an important test of a general theorythat underlies our understanding of fluid perco-lation and flow in ductile regions of Earth. This isof particular interest to the debate about wheth-er moderate dihedral angles can prevent thesegregation of core-forming melts in the deform-ing lower mantle (30–32). The inaccessibility of
Earth’smantle to field observations has preventedthe resolution of this debate. The observations offluid distribution in rock salt reported here showthat deformation-assisted percolation is possibleand suggest that core formation by percolationmay be a viable mechanism, even if the dihedralangle is above 60°.
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ACKNOWLEDGMENTS
S.G. is supported by the Statoil Fellows Program at TheUniversity of Texas at Austin. M.A.H. and J.E.G. were partiallysupported by NSF grants EAR CMG-1025321 and EAR-1348050,respectively. Imaging was performed at the High-ResolutionX-ray Computed Tomography Facility at the Department ofGeological Science, The University of Texas at Austin,which is partially supported by NSF grant EAR-1258878.Parts of image analysis was done on high-performancecomputing resources at Texas Advanced Computing Center.We are thankful to D. Ebrom, R. Hunsdale, and T. Løseth forproviding field data and guiding their analysis. The manuscriptalso benefited from constructive comments by M. P. A. Jacksonand R. A. Ketcham, as well as reviews from J. L. Urai and twoanonymous reviewers. The authors are grateful to the StatoilGulf Services LLC for granting permission to publish the fielddata. Other data are available in the manuscript as well as inthe supplementary materials. The authors claim no conflictsof interest.
SUPPLEMENTARY MATERIALS
www.sciencemag.org/content/350/6264/1069/suppl/DC1Materials and MethodsFigs. S1 to S7Database S1References (33–43)
25 June 2015; accepted 16 October 201510.1126/science.aac8747
Fig. 4. Fluid distributions in salt wells. Hydro-carbons signs frommud logs of all 48wells covering150,000 m of salt are shown as a function ofdihedral angle (13).Wells are divided into 14 groupsbased on spatial proximity. Salt extent is shown byan arrow in each region. Theoretical fluid con-nectivity is indicated by gray scale (Fig. 1).Abbreviations denote the following protractionareas in the Gulf of Mexico: AT, Atwater Valley;GC, Green Canyon; KC, Keathley Canyon; MC,Mississippi Canyon; and WR,Walker Ridge.
, this issue p. 1069Sciencefor deep geological waste storage sites.hydrocarbons. If these salt domes are not completely isolated from the surrounding environment, they will not be suitable
found that some salt deposits in the Gulf of Mexico are infiltrated by oil and otheret al.repositories. Ghanbarzadeh Rock salt deposits are thought to be impermeable to fluid flow and so are candidates for nuclear waste
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