April 2013

AUTHORS

Anita Torabi Centre for Integrated Petro-leum Research (Uni CIPR), Uni Research, Allegt.41, N-5007 Bergen, Norway; [email protected]

Anita Torabi is a senior researcher and a projectleader at the Centre for Integrated PetroleumResearch (Uni CIPR), Uni Research. She holds a

Insight into petrophysicalproperties of deformedsandstone reservoirsAnita Torabi, Haakon Fossen, and Alvar Braathen

Ph.D. in petroleum structural geology from theUniversity of Bergen, Norway (2007). Her mainresearch activities include the mechanism andmechanics of faulting, fault-related folding, andfluid flow in deformed reservoirs; CO2 storageunderground; and diagenesis in fault zone.

Haakon Fossen Department of EarthScience, University of Bergen, Bergen, Norway;[email protected]

Haakon Fossen joined the University of Bergenafter several years as a structural geologistwithin exploration and production departmentsin Statoil. His current research interests includedeformation of sandstones, rifting, and con-tinental collisions. He holds a C.Sc. degree fromthe University of Bergen (1986) and a Ph.D.from the University of Minnesota (1992).

Alvar Braathen University Centre inSvalbard, Longyearbyen, Norway;[email protected]

Alvar Braathen works as a structural geologist forthe University Centre in Svalbard, following yearsat the Centre for Integrated Petroleum Research,University of Bergen, and the Geological Surveyof Norway. His current research covers sedi-mentary basin development, with a focus on faultand fracture characteristics. He holds C.Sc. (1991)and D.Sc. (1994) degrees from the University of

ABSTRACT

We use samples from undeformed and deformed sandstones(single deformation band, deformation band cluster, slip-surfacecataclasite, and fault core slip zone) to characterize their petro-physical properties (porosity, permeability, and capillary pres-sure). Relationships between permeability and porosity aredescribed by power-law regressions where the power-law ex-ponent (D) decreases with the increasing degree of deforma-tion (strain) experienced by the sample from host rock (D,9)to fault core (D, 5). The approaches introduced in this workwill allow geologists to use permeability and/or porosity mea-surements to estimate the capillary pressures and sealing ca-pacity of different fault-related rocks without requiring directlaboratory measurements of capillary pressure. Results showthat fault core slip zones have the highest theoretical sealingcapacity (>140-m [459-ft] oil column in extreme cases), al-though our calculations suggest that deformation bands canlocally act as efficiently as fault core slip zones in sealing non-wetting fluids (in this study, oil and CO2). Higher interfacialtension between brine and CO2 (because of the sensitivity ofCO2 to temperature and pressure) results in higher capillarypressure and sealing capacity in a brine and CO2 system than abrine and oil system for the same samples.

Troms, Norway.

ACKNOWLEDGEMENTS

This study has been partly funded throughConsortium R&D Project 429 207806/E20(IMPACT Project) and partly through the FaultFacies Project. We thank the sponsors of these

INTRODUCTION

The petrophysical properties of highly porous sandstone res-ervoirs undergo significant changes as a result of deformation.Knowledge of the petrophysical properties of deformed sand-stone and its undeformed host rock is essential for predicting

projects, the Research Council of Norway(CLIMIT and Petromaks programs), Statoil, andConocoPhilips. We also thank AAPG EditorStephen E. Laubach and the four reviewers JohnG. Solum, Andrew R. Thomas, Mark Andersen,and an anonymous reviewer for the constructive

Copyright 2013. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received March 6, 2012; provisional acceptance May 10, 2012; revised manuscript receivedAugust 30, 2012; final acceptance October 3, 2012.DOI:10.1306/10031212040

AAPG Bulletin, v. 97, no. 4 (April 2013), pp. 619637 619

comments. We thank Stephen Eaton for review-ing and copyediting the final version of themanuscript.The AAPG Editor thanks the following reviewersfor their work on this paper: Mark Andersen,John G. Solum, and an anonymous reviewer.

EDITOR S NOTE

Color versions of Figures 1 and 11 may be seenin the online version of this article.

620 Petrophysical Properties

fluid flow through such reservoirs. Faults are heterogeneousstructures whose geologic and petrophysical properties mayshow abrupt lateral variations that can make faults act as bar-riers, baffles, or conduits to fluid flow (Smith, 1966; Gibson,1994; Fisher and Knipe, 2001; Torabi and Fossen, 2009). Faultscan control fluid flow by juxtaposing reservoir rocks againstnonreservoir rocks or by making barriers to fluid flow throughseals or fault rocks (Fisher and Knipe, 2001). This may reduceproduction rates in a petroleum reservoir and, in case of CO2storage, may affect the injection rate and the total capacity ofthe reservoir. Consequently, faults may have considerable ef-fects on hydrocarbon field production and CO2 storage man-agement alike. One of the objectives of this article is to explorethe petrophysical characteristics (e.g., porosity, permeability,and capillary pressure) of fault-related rocks found in poroussandstones, using different methods for estimation of theseproperties, such as in-situ, laboratory, and image-processedbased (Torabi et al., 2008) methods. These results are used inanalyzing statistical and empirical relationships between thepetrophysical properties.

A common approach to fault seal analysis is to use simplealgorithms for seal capacity by clay smear, as reviewed byYielding et al. (1997). An alternate approach, which will beused in this study, considers faults (and stratigraphic seals) astabular zones whose sealing capacity is controlled by fault-intrinsic properties such as porosity and permeability. Thisapproach offers a possible assessment of capillary seal wherethe sealing capacity of the zone or layer relies on the size ofpore throats and capillary forces between wetting and non-wetting phases. The capillary seal model allows for partiallysealing faults, where the sealing capacity is governed by acritical pressure difference across the fault induced by thecapillary forces, that is, an equilibrium situation acquired overgeologic time in petroleum reservoirs that may be alteredduring production or injection (Fisher et al., 2001; Jolley et al.,2007). When the critical pressure is overcome for the liquidor vapor in question, flow is controlled by the relative per-meability of fluids (e.g., Manzocchi et al., 2010).

The fluid-flow behavior of faults in a petroleum reservoiris a function of their capillary entry pressure, porosity, per-meability, and spatial continuity (e.g., Gibson, 1994; Knipe,1997). The permeability of a fault zone is a function of its ar-chitecture (e.g., fault zone components and their geometry)and the flow properties of fault-related rocks and fractures(Caine et al., 1996; Fisher and Knipe, 1998; Gibson, 1998;Wibberley et al., 2008; Braathen et al., 2009).Major faults aregenerally surrounded by an enveloping volume of structures

lesinPercent)of

theSandsto

nesUsed

inThisStudy*

Plagioclase

Calcite

Dolomite

Siderite

Pyrite

Hematite

Total

Sandsto

neType

TR**

2.3

0.0

0.0

0.0

0.5

100

Quartz

arenite

0.0

TR0.0

TR0.0

0.0

100

Quartz

arenite

0.0

0.0

0.0

0.0

0.0

0.0

100

Quartz

arenite

TR5.4

TRTR

TRTR

100

Subarkose

tionby

Folk(1974).

edge of the sealing properties of faults, especially inmassive sandstones, remains uncertain and neces-sitates further analyses.

In this study, we use samples fromundeformedand deformed sandstones to characterize theirpetrophysical properties. The results allow for newstatistical ways of calculating capillary pressure ina sandstone reservoir with two-phase fluids (e.g.,brine [wetting phase] and oil-CO2 [nonwettingphase]), which are used to calculate themaximumnonwetting-fluid column height that can be sealedas a function of the effective pore-throat radius inthe reservoir. Through this study, we validate andexpand the empirical relations of Pittman (1992)by applying them on our large fault-related rockdata set to very different rock types and by introduc-ing new relations from laboratory measurements.

The approaches introduced in this work willallow geologists to use permeability and/or poros-ity measurements to estimate the capillary pres-sures and sealing capacity of different fault-relatedrocks without requiring direct laboratory measure-ments of capillary pressure.

Table1.

X-RayDiffractionAnalyses

(X-Ray

DiffractionMeasuredon

Powderof

Rock

Samp

Sample

Illite/Smectite

Illite+M

icaKaolinite

Chlorite

Quartz

k-Feldspar

Malha

Form

ation

0.0

0.0

0.0

0.0

97.2

0.0

Malha

Form

ation

0.0

0.0

1.6

0.0

98.4

0.0

MoabMem

ber

0.0

0.0

0.0

0.0

98.5

1.5

Slick

Rock

Mem

ber

0.0

3.9

0.0

0.7

79.7

10.3

*Notetheinterpretations

ofsandsto

netypesfro

mthex-raydiffractionanalyses

basedon

thesandsto

neclassifica

**TR

=trace.

DESCRIPTION OF DATA SET

Our samples come from the Entrada Sandstone(Slick Rock and Moab Members) of Utah (UnitedStates) and the Nubian sandstones (Malha Forma-tion) of Sinai (Egypt)two extensive sandstoneunits that together form a representative range ofcontinental reservoir sandstones. The data sets con-tain measurements from fault cores (slip zones andslip-surface cataclasite) and damage zone (mainlycataclastic deformation bands). The Slick RockMember of the Entrada Sandstone (Middle Juras-sic) is a subarkose (Table 1) and is composed of thinand laterally discontinuous eolian dune sandstonesinterbedded with muddy to sandy sabkha and in-terdune siltstones and sandstones (Foxford et al.,1996). The sandstone is predominantly fine to me-dium grained and moderately to well sorted. TheMoabMember of the Entrada Sandstone (Middle toUpper Jurassic) is a quartz arenite (Table 1) domi-nated by eolian dunes and is generally better sortedthan the Slick Rock Member as it contains fewer


fine grains (Foxford et al., 1996). The maximumburial depth of the Entrada Formation is estimatedto be 2.2 km (1.4 mi) by reconstructing the burialand thermal histories of the Paradox Basin (Nuccioand Condon, 1996; Ellingsen, 2011). The latestactivity of theMoab fault was reported to be of theearly Paleocene based on the age of clayminerals inthe damage zone of this fault (Solum et al., 2005).The sandstone of the Malha Formation is a quartzarenite (Table 1) and makes up the uppermost unitof the Nubian Sandstone sequence (Lower Creta-ceous, a prerift sequence). This formation consists offluvial sandstones with gravel lenses and mudstoneand kaolinite beds (Moustafa, 2003; Tueckmantelet al., 2010). The Malha Sandstone is moderatelysorted and medium to coarse grained. The maxi-mum burial depth of Nubian sandstones at thetime of faultingwas approximately 1.5 km (0.9mi)(Du Bernard et al., 2002; Torabi and Fossen, 2009).

In this contribution, we distinguish betweendeformation bands, dense deformation band clus-ters (decimeter-wide zones or swarms packed withdeformation bands), fault core slip zones, and slip-surface cataclasites, as shown in Figure 1B, C, D,and E. Our distinction of the latter two is based onthe slip-surface cataclasites (in walls of well-striatedand polished principal slip surfaces) that can befound in the studied units of both Utah and Sinai. Incontrast, fault core slip zones have not been de-scribed before. Fault core slip zones are encounteredin faults with 1- to 10-m offset in some of the Nu-bian Sandstone units and consist of multiple slipsurfaces hosted in variably crushed sandstone. Onmicroscale, the crushed sandstone appears as apoorly sorted mixture of crushed grains envelop-ing nearly undeformed but slightly rounded hostsandstone grains (survivor grains) and mildly de-formed sandstone lenses.

SCIENTIFIC APPROACH

Porosity and permeability are two widely usedpetrophysical properties that can be measuredthrough different approaches and at different sam-ple sizes. In contrast, capillary pressure data are

not so commonly found in the geologic literature,mostly because of cost and practicalities. Capillarypressure is the pressure difference between twoimmiscible fluids that are in contact in a porousmedia and can be measured by two types of pro-cesses: drainage (a nonwetting phase displaces awetting phase) and imbibition (a wetting phasedisplaces a nonwetting phase) (Dandekar, 2006).Pittman (1992) presented an inverse approach toempirically calculate capillary pressure for sand-stone reservoirs from laboratory-measured poros-ity and permeability. Thismethod has thepotentialof providing abundant amounts of inferred capil-lary pressure data, for example, from cored inter-vals in a reservoir. In this study, we have imple-mented the inversemethod of Pittman (1992) and,furthermore, used additional approaches to calcu-late the sealing capacity of our faulted sandstonereservoirs (for details, see approaches A, B, and Cin the next section). We use data derived fromdifferent methods, including laboratory-measuredporosity, absolute permeability, and mercury cap-illary pressure; in-situ measurements of perme-ability by minipermeameter (TinyPerm II); and es-timated porosity and absolute permeability throughimage processing of backscatter images of thinsections (Torabi et al., 2008; Torabi and Fossen,2009).

Capillary Pressure and its Relation to Porosityand Permeability Data

Capillary properties control the magnitude of thedifferential hydrocarbon buoyancy pressure ex-erted by a hydrocarbon column, which can bemaintained across a lithologic or structural bound-ary within a reservoir. Thus, capillary pressure andpore-throat size control the ability of a fault to actas a barrier or conduit to hydrocarbon flow on along-term (geologic) time frame, whereas the per-meability of rocks will influence the short (produc-tion or injection)-time fluid-flow pattern within areservoir (Schowalter, 1979; Gibson, 1998). In theinverse method implemented in this study, abso-lute permeability is used to calculate the capillarypressures of the samples. Among different types oflaboratory capillary pressure analyses, the mercury

Torabi et al. 623

injectionmethod is particularly interesting becauseit can provide insight into the pore-structure andpore-size distributions in a porous medium. Manyphysical properties of porous rocks are related totheir pore characteristics, and hence, their flowcharacteristics can be evaluated through mercurycapillary pressure analysis. In amercury drainage orinjection plot, the pressure atwhichmercury formsa connected pathway through the pores across thesample is called threshold pressure, which cor-responds to the inflection point (where the curvebecomes convex upward) on the plot (Figure 2;Katz and Thompson, 1987; Pittman, 1992). How-ever, the threshold pressure is sometimes difficultto measure (Pittman, 1992).

Some researchers have argued that, in log-logplots of drainage or injection curves, the apex pointof the hyperbola (the intersection points of the twoasymptotes on the hyperbola) presents an impor-tant capillary pressure value, in which the mercurymakes a connected pathway (Figure 3A; Thomeer,1960; Swanson, 1981). Nevertheless, Pittman (1992)commented that not all drainage curves show suchan apex point and suggested another way of plot-ting data for determining the apex point graphi-cally, which he claims to bemore accurate than thepreviously mentioned approaches. He plotted mer-


cury saturation normalized by mercury saturationpressure (y axis) against mercury saturation (x axis),as shown in Figure 3B. In this study, Pittmans(1992) method has been used to find apex pointson the capillary pressure data from 12 samples ofdeformed and undeformed sandstones (Table 2).Capillary pressure data were obtained through mer-cury injection into samples performed by Reslab(now Weatherford; for a detailed description ofthemethod, see the Appendix). The analyses wereperformed on eight samples from fault core slip

Figure 2. Semilog plot of mercury injectioncapillary pressuredata for a fault core slip zone sample from the Nubian Sand-stone. The threshold pressure corresponds to the inflection pointat which the curve becomes convex upward. This is the pressureat which mercury forms a connected pathway through the poresacross the sample. 1 psi = 6.9 103 mPa.

Figure 3. Two different ways to illustrate the apex point for thecapillary pressure data of a fault core (slip zone) sample from theNubian Sandstone. The apex point presents an important capil-lary pressure, in which the mercury (Hg) makes a connectedpathway through the sample. (A) Illustration of the apex point ina log-log plot of drainage or injection curve; the apex point in theresulted hyperbola is the intersection point of the two asymp-totes on the hyperbola. (B) Apex point in a plot of normalizedmercury saturation versus mercury saturation. The latter illus-tration has been used to obtain the apex points for all of thesamples in this study. 1 psi = 6.9 103 mPa.

zones of normal faults in the Nubian Sandstone(Malha Formation, Sinai, Egypt; samples I, J, K, L,M, N, R, and T [not listed] in Table 2), two sam-ples from single deformation bands in the SlickRock Member (samples A and F in Table 2) andone single deformation band sample in the MoabMember (sample O in Table 2) in the damagezone of the Moab fault, and one host rock samplefrom the Moab fault footwall (Moab Member,Utah, United States; sample U in Table 2). Duringsubsequent quality control of the data, one of thefault core samples (sample T) was excluded becauseof the poor quality of the laboratory data. Prepara-tion of the samples includes cutting the samplesinto small pieces (as much as 1.0 cm [0.4 in.]) tokeep only the deformed parts of the sample (faultcore slip zone or deformation band) and then in-jecting mercury into the samples. The measuredmercury capillary pressure data and the calculatedapex points for the different samples were used inthe study of empirical relationships between dif-ferent parameters (see approaches A, B, and C).

Approach AFor the samples with laboratory measurements ofmercury capillary pressure and porosity and per-

meability (Table 2), the following approach hasbeen used:

1. The capillary pressure data are plotted as mer-cury saturation/capillary pressure versus mer-cury saturation, and the plot is used to deter-mine the apex of Pittmans (1992) hyperbola(Figure 3B).

2. Then, mercury pressure data are plotted againstmercury saturation data, and the capillary pres-sure at the apex point is identified from the plot.Before using the mercury capillary pressure fur-ther, the pressure data have been converted to areservoir condition for crude oil (

calculated from the following relationship (Purcell,1949; Schowalter, 1979):

Pc 2scos qr 3

where Pc is the capillary pressure at the apexpoint (dyn/cm2), r is the effective pore-throatradius, q is the contact angle between two-phasefluids and solid, and s is the two-phase fluid inter-facial tension (Purcell, 1949; Schowalter, 1979).

The capillary pressure equation can be rewrit-ten in the following form (Schowalter, 1979;Vavra et al., 1992):

h 2scos qrgDr 4

where h (cm) is the maximum hydrocarbonfluid column height that can be sealed as afunction of the effective pore-throat radius(r), Dr (g/cm3) is the difference between thedensity of the two-phase fluids in contact with-in rock pore throats (in this study, brine and oil),and g is the acceleration of gravity (980 cm/s2

[386 in./s2]).From combining equations 3 and 4, we get

h PcgDr 5

where h (the fluid column height) can be easilycalculated by having capillary pressure at theapex point as the main variable.

Approach BFor other samples (core-plug samples and othermeasurements obtained through image processingof backscatter images of thin sections) from whichonly porosity and permeability data were avail-able, the following approach has been used:

1. The empirical relationship between porosity(f), permeability (k), and pore-throat radius atapex point (rapex, effective pore throat) foundby Pittman (1992) was used (equation 6; R2 isthe coefficient of determination). This empiricalrelationship is based onmeasurements (core-plug


porosity and permeability and capillary mer-cury injection) on more than 200 undeformedsandstone samples from 14 different formations(Pittman, 1992):

lograpex 0:117+ 0:475 log k0:099logf R2 0:91 6

2. Fromtheprevious capillarypressuredata (Table 2),rapex data were plotted against capillary pressuredata at apex points, and the statistical relation-ship between the two (equation 7) is used forcalculation of capillary pressure at apex pointsfor pore-throat radii obtained by equation 6(Figure 4). The calculated capillary pressure dataare then converted to a reservoir condition (brineand oil) using equation 2.

Pc 90:018r0:99 R2 1 7

3. The maximum nonwetting-fluid column height(h, the height of sealed hydrocarbon) that canbe stored in the samples can be calculated fromequation 5, assuming a two-phase fluid in areservoir condition (e.g., brine and oil).

Approach CFor samples from outcrops that only offered per-meability measurements from minipermeameterdata, the following approach was used:

1. The porosity term has been found to be with-out significance in equation 6 (Pittman, 1992).

Figure 4. Correlation between capillary pressures at apex pointsand their related pore throats for mercury-injected samples.

To further test this finding, we have examinedthe significance of porosity in our calculationsand found that the differences are small and oflittle significance (Figure 5). Therefore, a regres-sion (equation 8) that does not include porosityas a variable has been used to calculate pore-throat radius at apex points. This regression wasmade by correlating our laboratory-measuredpermeability and pore-throat radii at apex points.However, Pittman (1992) has suggested a dif-ferent relationship between these two param-eters (equation 9), which, when applied to ourdata, results in a slightly higher pore throat thanwhat we get from equation 8.

lograpx 0:123+ 0:37logk R2 0:808

lograpx 0:226+0:466logk R2 0:909

2. Equation 7 has been used to calculate the cap-illary pressures at the apex points. The calculatedcapillary pressures are then converted to a res-ervoir condition (brine and oil) using equation 2.

3. The maximum nonwetting-fluid column height(h) that can be stored in the samples can be cal-culated from equation 5 assuming a two-phasefluid in a reservoir condition (brine and oil).

RESULTS

Permeability-Porosity Relationships

In addition to the porosity and permeability data ofthe samples used inmercury injection experiments(Table 2), we make use of an extensive porosity-permeability database based on other types of mea-surements (core plug and image processing of thinsections), as shown in Figure 6. The rocks usedfor these measurements include the sandstonesfrom the same or similar units as those presentedin Table 1. The relationship between porosity andpermeability data from core-plugmeasurements ofa host rock, a single deformation band, a cluster ofdeformation bands, and fault core slip zones havebeen studied (Figure 6A). The results show that,for all of the samples, this relationship fits a robustpower law but that the power-law exponent (D)depends on the degree of deformation experienced

Figure 5. Pore throat radius at apexpoints (rapx) have been calculated by in-cluding porosity (x axis) and removingporosity (y axis) for core-plug data. Theplot shows that porosity is not significantin the calculation.

Torabi et al. 627

by the samples. More specifically, D ranges fromapproximately 9 for the host rock samples to ap-proximately 5 for the fault core samples (Figure 6A).


Furthermore, for a given porosity, host rock sam-ples have higher permeability than deformed rocks,and the permeability at a given porosity decreases

Figure 6. Permeability-porosity relation-ship for all of the samples. Permeability-porosity relationship for core-plug samples(host rock, single deformation band (DB),cluster of DBs, and fault core slip zone)(A) and for host rock and single DBs fromimage processing of thin sections (B). Thefitted curves to the data are power laws.The power-law exponent decreases as thedegree of deformation increases in thesamples.

with the amount of deformation (Figure 6A). A sim-ilar relationship can be obtained from permeability-porosity data estimated through image processingof the thin sections (Figure 6B), although the ex-ponents are slightly different from those obtainedfor core-plug samples and are also less well defined.This is because themeasured sample sizewas smallerthan that of the core plugs. This is particularly truefor deformation bands, where we measured onlythe properties of the bands with no part of the hostrock included (Torabi et al., 2008). Therefore, thedeformation band porosity and permeability val-ues estimated from image processing are slightlylower than the values that are obtained from coreplugs (Figure 6B).

Capillary Pressure Measurements

Detailed information on the properties of the sam-ples used in mercury injection experiments are pro-vided in Table 2. The laboratory mercury capil-lary pressure and pore-throat radii of the samples(approach A) are compared to the calculated ca-pillary pressure and pore-throat radii (approach B)of the same samples in Table 2. A comparison ofthe semilog drainage (injection) plots (Figure 7A,B) for our mercury capillary pressure measure-ments reveals that the drainage curves for faultcore slip zone samples are different from those ofdeformation band and host rock samples. Thedeformation band and host rock samples closely

Figure 7. Comparison of thesemilog drainage (injection) plotsfor mercury-injected samples re-veals that the drainage curve forfault core slip zone samples is dif-ferent from those of deformationband and host rock samples. (A) Thedrainage curve for fault core slipzone samples for most of the sam-ples has more than one inflectionpoint. (B) The deformation band andhost rock samples follow almost astandard drainage curve after theinflection points, with some slightchanges in high capillary pressures.Samples are presented in Table 2.1 psi = 6.9 103 mPa.

Torabi et al. 629

brine (in the range of 2040 mNm1) will controlthe resulting capillary pressure because the in-terfacial tension has shown a pronounced depen-dence on pressure and temperatures in the ex-periments run on brine and CO2 (e.g., Kvammeet al., 2007; Angeli et al., 2009). Depending on theselected interfacial tension (s) for brine and CO2(smin 20mNm1 and smax 40mNm1; Angeliet al., 2009), the corresponding capillary pres-sure changes. A higher interfacial tension results inhigher capillary pressure values in the brine andCO2 system for the same samples. This in turn willaffect themaximumheight of the CO2 column thatcan be stored through capillary forces.

Among the different trapping mechanisms in-volved in the sequestration process of CO2, thecapillary trapping mechanism could be the mosteffective (Wildenschild et al., 2011). In contrast tothemercury capillary experiments discussed in thisstudy, capillary trapping of CO2 commonly occursduring the imbibition of brine, when CO2 is mi-grating upward and brine imbibes back into theformation because of density difference (buoyancyforces), after the injection of CO2 has stopped. Atthe imbibition process, the capillary pressure (re-sidual or minimum capillary pressure) locks CO2at the pore scale and hence inhibits large-scalemovement of CO2 within the aquifer (Wildenschildet al., 2011).

CONCLUSIONS

This study focuses mainly on the properties offault-related rocks in clean sandstones, that is, with-out significant clay minerals. We have studied sam-ples of host rock, deformation bands, fault core slipzones, and slip-surface cataclasite from the EntradaSandstone (Slick Rock and Moab Members) andNubian sandstones (Malha Formation).Our resultsshow the following:

1. Power-law regressions canbe fitted to theporosity-permeability data obtained through laboratorymeasurements. TheD has a reduction from hostrock (D,9) to fault core (D,5) in accordancewith the increasing strain experienced by the

samples. For a given porosity, permeability ishigher in host rock samples than in deformedsamples and will decrease with the degree of de-formation in the samples.

2. The approaches introduced in this work willallow geologists to use in-situ (field), core-plug,and thin section (image processing) measure-ments of permeability and/or porosity to esti-mate the capillary pressures and sealing capacityof different fault-related rocks without requir-ing direct laboratory measurements of capillarypressure.

3. The sealing capacity of fault core slip zone wasfound to be higher than that of single deforma-tion bands and clusters of bands. Our calcula-tions suggest that a fault core slip zone offersmore than 140-m (459-ft) height of hydrocar-bon in extreme cases. A cluster of deformationbands can locally act as efficiently as a fault coreslip zone or slip-surface cataclasite in increasingcapillary pressure and sealing the nonwettingfluid.

4. A higher interfacial tension between brine andCO2 in a brine and CO2 system will result in ahigher capillary pressure and sealing capacity forthe same samples when compared to a brine andoil system.

APPENDIX: MERCURY INJECTION METHOD

The main components of the mercury injection apparatus area mercury pump for injection, a chamber to house the sam-ple, pressure gauges, and devices for volume measurements.A sample with a known porosity and permeability is placedinto the selected penetrometers in the mercury chamber andis completely evacuated before the mercury is injected intoit. The injected mercury represents the nonwetting phase,the volume of which increases with increasing pressure untilthe sample is saturated by mercury (Dandekar, 2006). In theinstrument used for the mercury injection at Reslab (Au-topore IV 9520), initially, several pressure steps are definedin a pressure table over a range from vacuum to 60,000 psi(414 mPa). The Autopore software automatically takesreadings between points on the pressure table until themaximum level of intrusion is detected. This maximum in-trusion is also predetermined based on the petrophysicalparameters of the sample and is presented in milliliters ofmercury per gram of the sample. The pressures and satura-tions measured during the experiments make the drainagecapillary pressuresaturation curve. The volume of mercury

Torabi et al. 635

in the penetrometer stem is measured by determining thepenetrometers electrical capacitance. The data are furtheranalyzed using the Young-Laplace equation.

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Orapan Limpornpipat PTT Exploration andProduction Public Company Limited, 555 Vibhavadi-Rangsit Road, Bangkok 10900 Thailand;[email protected]

Orapan is a geophysicist in the corporate geophy-sical team in PTT Exploration and Production. Herduties primarily consist of providing services inseismic acquisition, seismic data processing, andquantitative interpretation. She graduated fromChiang Mai University, Thailand, in 2006 with abachelors degree of science in physics and has alsoundertaken a study program in geology.

Kanjana Krisadasima PTT Exploration andProduction Public Company Limited, 555 Vibhavadi-Rangsit Road, Bangkok 10900 Thailand;[email protected]

Kanjana is currently vice president for MyanmarPetroleum Development in the International AssetGroup of PTT Exploration and Production Interna-tional Limited. She graduated from Chang MaiUniversity in Thailand and has worked extensivelyon petroleum exploration and productionthroughout Thailand and Myanmar.

Suwit Pabchanda PTT Exploration andProduction Oman Company Limited, P.O. Box1067, P.C. 133, Al Khuwair, Muscat, Oman;[email protected]

Suwit Pabchanda has more than 20 years ofexperience in the petroleum industry. He obtaineda bachelors degree in 1991 before joining PTTExploration and Production. He has worked as anexploration and development geophysicist in theGulf of Thailand, Malaysia, the deep offshoreAngola, Myanmar, and Oman. He is currentlysubsurface manager for PTTEP Oman CompanyLimited in Muscat, Oman.

Hamish R. Macintyre BG-Group GlobalTechnology Centre BG Brazil, Av. Repblica doChile, 330-25th floor Torre Oeste Centro, 20031-170, Rio de Janeiro, Brazil; present address: BG-Group Global Technology Centre BG Brasil, Av.Repblica do Chile, 330-25th Floor Torre DeskCentro, 2003 1-170, Rio de Janerio, Brazil;[email protected]

Hamish is geophysics technology manager in theBG Group Global Technology Centre. Hamishreceived a B.Sc. (honors) in physics and geologyfrom the University of Glasgow. Since 2004, he hasworked for the BG Group on geophysical researchand development and as an exploration anddevelopment subsurface manager. Before joining

640 Origin of Overpressure in the Northern Ma

(0.676 psi/ft) and not lithostatic magnitudes as commonlyhypothesized. The gas generation overpressures in this articleare not associated with a significant porosity anomaly and rep-resent a major drilling hazard, with traditional pore-pressureprediction techniques underestimating pressure gradients by2.3 1.5 MPa/km (0.1 0.07 psi/ft).

INTRODUCTION

Abnormally high pore-fluid pressures (overpressures) represent asignificant drilling hazard, and accurate pore-fluid pressure (typi-cally termed pore pressure) prediction is critical for well plan-ning, casing point selection, drilling procedures, and completions(Law and Spencer, 1998; Sayers et al., 2002). However, reliablepore-pressure prediction in many regions first requires an under-standing of the origins and distribution of overpressures and howdifferent overpressure generation mechanisms affect the petro-physical properties of sediments (Hermanrud et al., 1998; vanRuth et al., 2004). Overpressures are generally considered to begeneratedby twodistinctmechanisms, disequilibriumcompactionor fluid expansion and transfer processes, with each having dif-ferent petrophysical signatures and, thus, requiring different pore-pressure prediction strategies (van Ruth et al., 2004; Tingay et al.,2009a). Most overpressures observed in sedimentary basins aregenerated by disequilibrium compaction, in which overpressureis the result of loading (through burial or high horizontal stresses)of effectively sealed sediments (Mouchet and Mitchell, 1989;Osborne and Swarbrick, 1997). Disequilibrium compaction over-pressures are typically associated with abnormally high porosities(undercompaction) and commonly exhibit clearly observable seis-mic velocity anomalies (Mouchet and Mitchell, 1989; Bowers,1994; Osborne and Swarbrick, 1997).

Fluid expansion overpressuring comprises a suite of mech-anisms in which the relative volume of pore fluid increaseswithin a confined volume of sedimentary rock (Mouchet andMitchell, 1989; Bowers, 1994;Osborne and Swarbrick, 1997).Overpressures generated by fluid expansion mechanisms arenot associatedwith a porosity anomaly and aremore difficult todetect and for pore pressures to be quantified (Miller et al.,2002; Gutierrez et al., 2006). Hypothesized fluid expansionoverpressure generation mechanisms include aquathermal ex-pansion, smectite, kaolinite or gypsum digenesis, load transfer,vertical transfer, and gas generation (Mouchet and Mitchell,1989; Neuzil, 1995; Osborne and Swarbrick, 1997; Swarbrickand Osborne, 1998; Tingay et al., 2007; Lahann and Swarbrick,2011). However, of all proposed fluid expansion or transfer

lay Basin

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