Experimental Character is at Ion of the Hydrocarbon Sealing Efficiency

8/8/2019 Experimental Character is at Ion of the Hydrocarbon Sealing Efficiency

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ELSEVIER

Marine and Perroleum Geolo,yj~.Vol. 14. No. 5, 565 -580. 1997p.I 1 1997 Elsevier Science Ltd

All rights reserved. Printed in Great BritainPII : O264-6172(97)00022-6 0264-8 I72/97 $17.00 i 0.00

Experimental characterisationsealing efficiency of cap rocks of the hydrocarbon

S. Schlijmer and B. M. Krooss*Institute of Petroleum and OrganicGmbH, D-52425 JBlich, Germany

Geochemistry KG-41, Forschungszentrum Jiilich

Received 13 April 1996; revised 17 February 1997; accepted 2 March 1997Jurassic shales and mudrocks from the Haltenbanken area offshore Norway and red claystonesfrom Carboniferous and Permian intervals of Northern Germany were used in a study of thehydrocarbon sealing efficiency of elastic sediments. The investigations comprised geochemicaland mineralogical analysis of the pelitic rocks, petrophysical characterisation by mercury poro-simetry and specific surface area measurements, and laboratory experiments to assess thetransport properties with respect to both molecular transport (diffusion) and volume flow (Darcyflow). Effective diffusion coefficients of methane in the water-saturated rock samples at 150C laybetween 1.4x IO- and 4.5x 10-0m2/s and showed a distinct correlation with TOC content.Permeability coefficients, measured by means of a steady-state method, ranged from < 1 nDarcy(4 loo* m2) for Permian (Rotliegend) and Carboniferous red claystones up to 4.3 PDarcy(4.3 x 10~8m2) for a bioturbated Jurassic siltstone.

The experimental data were used to calculate maximum sustainable gas and petroleum columnheights, hydrocarbon leakage rates by pressure-driven volume flow (Darcy flow), and diffusivegas losses for simple, hypothetical scenarios. Computed maximum gas column heights rangefrom 20m up to >2000m. Hydrocarbon column heights calculated on the basis of a rich con-densate lay between 3 and 340 m. Depending on temperature, pressure, reservoir geometry andseal thickness, diffusive losses can be expected to require tens of millions of years to significantlyaffect the contents of commercial size natural gas reservoirs. 0 1997 Elsevier Science Ltd.Keywords: cap rocks; shales; sealing efficiency; displacement pressure; permeability; porosity; diffusioncoefficient; methane; Haltenbanken; N German basin

The evolution of hydrocarbon accumulations on the geo-logic time-scale is a dynamic process which is controlledby the rates o f supply and loss of petroleum. Improved2D basin modelling techniques and upcoming 3D modelshave the capability of treating oil and gas migration inthe context of basin evolution. These numerical method srequire, howe ver, reliable petrophysical and fluid trans-port param eters for the various lithologies encounteredin hydrocarbon systems. While the characterisation ofthe transport process es in reservoir rocks has become awell established discipline with a large knowledge-base,the corresponding information on low porosity and lowpermeability source rocks and seal lithologies (caprocks) is scarce. As pointed out by Sylta (1993 ) cap rockleakage is still one of the least studied proces ses in thefield of basin modelling.

Besides evaporitic sequences, which are commonlyattributed excellent sealing efficiencies, shales representthe most important cap rocks in many pe troliferousareas. Presently only a limited data bas e is available onpetrophysical and transport properties of tight shalesand claystones (Bredehoeft and Hanshaw, 1968; Magara,1971; Brace, 1980; Morrow et al., 1984). Katsube et al.(1991) and Mudford et al. (1991) report permeabilitydata for a small number of tight shales measured under*Author to whom correspondence should be addressed.

lithostatic stress. Over a range o f effective stresses from2.5 to 60 MPa (36&87OOpsi) the permeabilities werefound to range from 16 down to 0.1 nDarcy (nDarcy =nanodarcy; 1 nDarcy = lo- D arcy = lo- m)

In order to arrive at a better understanding and animproved quantification and prediction of sealingefficiencies of cap rocks an experimental study wa s carriedout on a number of selected cap rock lithologies fromoffshore Norway and northern Germany. Using speciallydesigned experimental equipment (cf. Figure I) per-meability measurem ents down to the nanodarcy rangewere carried out on a total of 27 rock sa mples from sealsof different sedimentological environments. The sampleswere charac terised by mineralogical, geochem ical andpetrophysical method s. In addition. diffusion coefficientsfor methane were measured under elevated pressure andtemperature conditions (3.0 MP a, 150C) to quantify therate and efficiency of molecular transport of natural gasthrough cap rocks.

Theory of hydrocarbon en t rapmentThe basic concepts of hydrocarbon entrapment are wellestablished and have been discussed by a number of wor-kers. Berg (1975) presents the concepts of capillary sea-ling and its role in hydrocarbon migration and trapping.A comprehensive overview of this mechanism has been

565


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566 Hydrocarbon sealing efficiency of cap rocks: S. Schliimer and B. M. Krooss

douciou~-layeredporous stainlesssteel disks

. rock sample

Figure 1 Schematic view of flow cell used for permeability anddiffusion measurements on cap rocks

given by Schow alter (1979) while the work of Hubbert(1953) emphas ises the hydrodynamic aspects of hydro-carbon e ntrapment. Down ey ( 1984) stresses the import-ance of seal characterisation in risk evaluation and pointsout that hydrocarbon seals need to be evaluated on amicro and a mega sca le. The establishment of a linkbetween the macro scale and petrophysical and transportparame ters which can only be measure d experimentallyon the laboratory (micro) scale is one of the fundamentalproblems in the analysis of basinwide fluid flow.

Apart from events like seismically induced seal ruptureor tectonic deform ations resulting in the formation ofconducting faults (which may persist only over limitedperiods of geologic time) the retention of hydrocarbonsby overlying seals is controlled by the capillary entrypressure, the permeability and relative permeability andthe extent o f diffusive los ses (molecular transport)through th e fluid-saturated pore space .

Capillur~l forces inhibit volume flow of a non-wettinghydrocarbon phase through a seal until the pressure ofthe underlying hydrocarbons excee ds the capillary entrypressure. Leak age occurs when an interconnected flow-path of the hydrocarbon phase forms across the poresystem of the cap rock. In an analysis of various cap rockand fault seal situations Watts (1987) denotes these sealsas membrane seals. The capillary sealing efficiency ofmembrane seals depends critically on the wettability ofthe cap rock. Problems relating to wettability changesduring hydrocarbon leakage and the reversibility of sealfailure are largely unexplored. Under hydrostatic con-ditions a hydrocarbon column of a certain height isrequired to create the buoyancy pressure which caneventually compen sate and excee d the capillary entrypressure. The dependence of the capillary sealingefficiency on the petroleum fluid phases (gas and oil) hasbeen discussed by Watts (1987 ). Gas-w ater interfacialtension is larger by around one order of magnitude thanoil-water interfacial tension. As a consequence a gas capon top of an oil column will enhance the sealing efficiency.Due to its lower density, a gas column will exert a higherbuoyancy pressure than an oil column of equal height.Gas density is, howev er, strongly p ressure dependent andat greater depth the buoyancy forces exerted by gascolumns decrease substantially.

In the case of overpressure d reservoir compartme nts

capillary seal failure cannot be related to absolute hydro-carbon column height but buoyancy pressures will stillrepresent a factor in controlling sealing efficiency in thiscase. Lithologies with extremely high or infinite capil-lary entry pressure s are referred to as hydraulic seals(Watts, 1987). Here seal failure is only possible by mech-anical fracturing due to build-up of excessive fluid pres-sure or tectonic events (cf. Caillet, 1993).

Permeabilit~~and relative permeability will control pet-roleum fluid transport through the seal once the capillaryentry pressure has been excee ded. T he hydrocarbon col-umn he ights within a reservoir will then be determinedby the relative rates of charge and leakage. Petroleumleakage through an initially water-w et seal is likely tochange its wettability to oil-wet. This will result in areduction or complete loss of capillary sealing efficiency(cf. Ingram and Naylor, 1996) and subsequently the leak-age process will be controlled exclusively by permeability.

Permeability is also an important param eter con-trolling overpressure build-up and decay in sedimentarysystems. The maintenance of anomalous fluid pressureseven over limited periods of geologic time requires thepermeability of sedimentary sequences to be extremelylow. Bredehoeft and Hanshaw (1968) assume hydraulicconductivities in the range of lO_cm s correspondingto permeabilities of lo- m2 or 1 nDarcy. Permeabilitydata for tight shales are required for the interpretation ofoverpressure and fluid how in sedimentary basins.Diffusion is a perpetual and ubiquitous proces s in sedi-mentary basins and its role in hydrocarbon migration hasbeen analysed by several workers (e.g. Antonov, 1954,1958, 1964, 1970; Smith et al., 1971; Neste row andUschatinskij, 1972; Leythae user et al., 1980, 1982; Kroossand Schaefer, 1987; Krooss and Leythaeuser, 1988;Krooss rt LzI., 1992a, 1992 b; Nelson and Simmons, 1992.1995; Monte1 et al., 1993). Although some controversypersists on the quantitative aspects of this issue, diffusivetransport, according to present understanding, may rep-resent a significant process in the dismigration of naturalgas in certain situations. Its relevance for oil dismigrationis considered marginal. Numerical modelling based onexperimental diffusion p arame ters (cf. Monte1 et al..1993; Hantschel et al., 1995) can help to identify situ-ations whe re diffusion is of critical importance for thepersistence of natural gas accumulations.

In the present study it was attempted to arrive at quan-titative data for the process es and mechanisms outlinedabove for a selection of potential seal rocks.

SamplesThe samples used in this investigation originate from fourwells in the Smorbukk field, Haltenbanken area, offshoremid-Norw ay and from several wells in northernGermany. The requirement of cored samples for theexperimental work imposed a serious limitation becausecoring is usually pe rformed in reservoir sequences andcores from seal intervals are rare.Haltenbanken areaThe geologic situation of Haltenbanken and the Smor-bukk field has been described by various authors (e.g.Aasheim et al., 1986; Heum et al., 1986; Ungerer et al..1987; Forbes et al., 1991; Ehrenberg et al., 1992).

Fifteen samples from the Smarbukk field were used in


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Hydrocarbon sealing efficiency of cap rocks: S. Schltimer and B. M. Krooss 567Table 1 Sample information and petrophysical parameters of cap rocks from Haltenbanken and the North German Basin

Sampleno. Formation Rock type

HI MelkeH2 MelkeH3 MelkeH4H5H6H7H8

MelkeMelkeMelkeMelkeNot

H9HI0HI1HI2HI3

Upper RorLower RorLower RorTiljeTilje

HI4 TiljeHI5 Tilje

NlN2N3N4N5N6N7N8N9NIONilN12

Upper RotliegendUpperCarboniferousUpper RotliegendUpper RotliegendUpper RotliegendUpper RotliegendUpper RotliegendUpperCarboniferousUpperCarboniferousUpperCarboniferousUpperCarboniferousUpperCarboniferous

Death TOC Porosity[r;ll [%I

HaltenbankenI%1

homogeneous claystonehomogeneous siltyclaystonecoarse grained siltstonewith detrital hloritehomogeneous claystonemicritc limestone (siderite)homogeneous claystonehomogeneous claystonefinely laminated, TOC-rich clay/siltstonecoarse grained bioturbatedsiltstonecoarse grained bioturbatedsiltstoneclaystone with minorinterlayers of siltalternate bedding of clay,silt and sand (ripple marks)alternate bedding ofquartz-free clay layers andcoarse grained sil tfine and regularlylaminated silt/claystoneclaystone with minorinterlayers of silt

3972.43973.73976.64184.74197.54209.54227.74043.54145.74495.84683.14238.44263.5

4527.4 0.3 1.74560.0 1.78 0.7

0.541.350.772.491.062.820.845.441.030.571.560.850.91

red claystonered claystone

North German Basin1482.2 0.031837.3 0.04

0.9 n.m. 10.54 450.3 75.7 4.21 46

fanglomerate 4979.9 0.03 6.6 1370 2.55 5.9fanglomerate 4990.2 0.02 6.6 1350 3.23 6.1red claystone 4643.4 0.04 0.7 7.8 25.32 175red claystone 4655.1 0.05 0.7 0.62 21.58 51red claystone 4796.2 0.03 0.5 50.0 9.1 51red claystone 4053.1 0.05 1.9 13.3 5.26 62red claystonered claystonered claystonered claystone

3572.2 0.073394.7 0.023396.5 0.021 5 4 9 . 6 0.03

0.8 26.6 9.73 1240.6 3.5 4.34 (1.8)0.4 1.8 4.71 (5.3)1.5


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568 Hydrocarbon sealing efficiency of cap rocks: S. Schliimer and 9. M. Kroosselectron m icroscopy (SEM ) on selected samples. T otalquartz content was quantified by XRD -measurem entsagainst an internal standard (TiOZ). The total amountof phyllosilicates was estimated by the aluminium oxidecontent (mea sured with X-ray fluorescence spectrome try,XRF ) assuming an average of 40% Al,O, in micas andclay minerals and due to the fact that other Al,O,-bearingminerals (feldspars) were nearly absent. Organic andinorganic carbon (for calculation of carbonate content)and total sulphur to estimate the pyrite and sulphatecontent were measure d by standard LECO -analysis. Dueto the low TOC-content of the samples from northernGermany, ROCK -EVAL analysis was only carried outon the samples from Haltenbanken.Pe tr ophJ k c a l me thods

Speci f ic sw face area. The specific surface area isone of the factors affecting the permeability of soils andsedimentary rocks and appea rs in semi-empiricalrelationships like the Kozeny-Carman formula (seebelow). Specific surface areas of the rock samples weredetermined by nitrogen adsorption using a MICR O-MER ITICS Gemini 2360 instrument. Cuttings with agrain size < 1 mm were dried for 72 h at 80 C. Approxi-mately 3.5 g were then filled into a glass tube and de gassedat 130 C for 2 h. After cooling the sample tube to liquidnitrogen temperature , the adsorbed nitrogen volume wasdetermined at five different pressures ranging from 5 to20% of the saturation pressure P,). The evaluation wascarried out according to a modified BET formula (Bru-nauer et cil., 1938) for low relative pressures.

Me r c ur y por os ime t r y . Mercury porosimetry was per-formed to determine the total porosity and capillary sea-ling efficiency of the cap rocks samples. In order tominimize surface effects the measurem ents were carriedout with cylindrical plugs of 1 cm diameter and 44.5 cmlength. Capillary entry curves were recorde d with aQUANTACH ROME AUTOSCAN 60 porosimeter. Theequivalent pore radius r was computed according to thecapillary pressure equation (Washburn, 1921; Purcell,1949; Rootare, 1970):

r= _~rm,where

P,. = capillary pressure [Pa]y = interfacial tension [Nm-I, (yHg,alr= 0.471 Nm-)

0 = wetting angle, (OHplldlT 140)According to this equation the radius of pores acce ss-

ible to mercury intrusion depends on the pressure applied.In the present study mercury intrusion was measure d upto a pressure of 345 MPa (3.45 kbar, 50,OOOpsi) cor-responding to a minimum equivalent pore radius of2.1 nm (21 A). Porosity values derived from thesemeasurem ents consequently encompa ss only the volumeof pores w ith larger equivalent radii. Many of the peliticrock samples investigated had a considerable portion ofmicropore volume (pore radii ~2.1 nm) which wasbeyond the scope of resolution of mercury porosimetry.In some instances an indirect estimate of the totalporosity, including microporosity could be derived fromthe diffusion experiments (see below).

Figure 2a show s a mercury capillary pressure curve todescribe the terminology and the interpretation pro-

log (P/[MPa])

1 10 10 0 1000R I4

Figure 2 Capillary pressure curve from mercury porosimetrymeasurement: (a) intrusion volume vs mercury pressure; (b)intrusion volume vs equivalent pore radius and pore radius dis-tribution

cedure used in this work to represent the pore structureand quantify the capillary sealing efficiency of sedi-mentary rocks. The volume of mercury entering the poresystem of the rock sam ple is plotted as a function ofpressure on a logarithmic scale (Hg intrusion curve). Thepressure at which mercury starts to penetrate into thelargest pores of the pore system (after correction forsurface rough ness effects) is denoted as entry pressure(RP) . The two other characteristic pressure values cor-respond to the inflexion point (PP) of the sigmoidal capil-lary pressure curve and the intersection (DP) of thetangent to this inflexion point with the logarithmic pres-sure axis. The inflexion point m arks the pressure at whichthe incremental rate of intrusion of mercury with increas-ing pressure is highest and, in terms of pore size distri-bution, it represents the most prominent pore radius.Another common representation of the capillary pressurecurve as a function of equivalent pore radius is given inFigure 2b. The first derivative of this curve showing thecorresponding pore size distribution is also included.

Mercury capillary pressure curves are used to estimatethe displacement pressure , which is a critical parame terfor hydrocarbon sealing capacity. Displacem ent pressureis defined as that press ure required to form a continuousfilament of non-wetting fluid through the largest con-nected pore throats of the rock (Schowalter, 1979).

Schowalter (1979) performed unidirec t ional capillary-breakthrough experiments with nitrogen and mercury onlaboratory samples of sandstone, chalk and silty shale upto pressures of 34MPa (5,000 psi). Non-wetting phasesaturations required for the establishment of an inter-connected pathw ay across the length of the samplesranged between 4.5 and 17.0% . B ased on this evidence


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570 Hydrocarbon sealing efficiency of cap rocks: S. SchlLimer and B. M. Krooss

1 0 1 0 0Pressure MPa]

I O 1 0 0Pressure MPa]

181 61 4s

s 1 2E 1 0

z 8g 6

p 420

1 0 0 01 0 1 0 0Pressure MPa] Pressure MPa]

3 0 3 0

2 5 2 57 5 a5 2 0 5 2 0E f 1 5

/I 1 5s " 2 / H42 I OB

E t I OB

5 5

0 01 1 0 1 0 0 1 0 0 0 1 I O 1 0 0 1 0 0 0

Pressure MPa] Pressure MPa]Figure 4 Capillary pressure curves from mercury porosimetry for cap rocks from northern Germany (N] and Haltenbanken (H]: (a]Carboniferous claystones (N); (b) Rotliegend claystones (N]; (c] Rotliegend fanglomerates (N]; fd] Lower Jurassic claystones (Tilje, H];(e] Middle Jurassic claystones (Ror and Not, H]; ff] Upper Jurassic (Melke, H]

struction of the tangent for the assessme nt of the dis-placement pressure value (DP) is based on the steepes tslope found in the experimental curve. For simple, mono-modal intrusion curves this pressure corre sponds toroughly 10% mercury saturation. For the more complexintrusion curves displacement pressures cannot bederived without ambiguity. A more reliable assessmentof the sealing efficiency would require unidirectionalmeasurem ents at high pressure levels. The displacementpressures (DP ) for mercury obtained from the evaluationprocedure are indicated on the corresponding capillarypressure curve in Figure 4.

view of a flow cell which was use d for both the diffusionand permeability measurem ents. Cylindrical sampleplugs w ith a diameter of 28.5 mm and a thickness between6 and 20mm are machined from the core samples andplaced between two pistons. Porous stainless steel discson both sides of the sample plugs act as fluid reservoirs.Conduits within the pistons a re used for introduction andremoval of fluids during the experiments.The flow cell shown in Figure I does not allow forcontrolled application of axial load. A tri-axial flow cellis presently used to perform permeability and diffusionmeasurem ents as a function of effective stress.

Measur emen t of perm eability and diffusioncoefficientsThe experimental equipment used to study transport pro-cesses in sedimentary rocks was developed at the For-schungszentrum Jiilich. It consists of flow cells andperipheral instrumentation to perform volume flow anddiffusion measureme nts on sedimentary rocks at elevatedpressures and temperature s. Figure I shows a schematic

Pe r me ab i l i t y me as ur e me n t sFor the permeability measurem ents the arrangement ofrock sample, porous discs and pistons was surroundedby a PTFE shrink tube and pla ced into a thin-walled(0.15 mm) aluminium tube. Application of a confiningpressure between 15 and 20 MPa (22,000&29,000 psi)assured a leak-tight seal around the sample and preventedbypassing of water during the permeability measure-


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Hydrocarbon sealing efficiency of cap rocks: S. Schldmer and 6. M. Krooss 571ments. In accordanc e with the maturity stage of the shalesamples the mineralogical analysis show ed no evidenceof swelling clay minerals (smectites). Therefore the use ofbrine could be avoided and the permeability measure-ments we re perform ed with fresh water. All permeabilitytests in this study were carried out at room temperature .

A modified H PLC pump (SHIMADZU , LC6A) wasused in a constant pressure mode to generate a pressuregradient across the sample. To obtain measurab le flowrates the upstream pressures were set to values between3 and 8 MP a (4,300-l 1.600 psi). Depending on samplethickness the corresponding pressure gradients re achedup to 850 MP a m-. Permeability tests with different pres-sure gradients on the same sample indicated no measur-able deviation from Darcy s law under the experimentalconditions used. Due to the dependence of permeabilityon effective stress (c f. Katsube et ul., 1991) high fluidpressures associated with high pressure gra dients may,howe ver, affect indirectly the permeability of mudrocksby reducing effective stress .

The permeability measurem ents were performe d in asteady-state mode. The flow was monitored auto-matically via the pumping rate required to maintain theupstream pressure. In addition the fluid volume passingthrough the sample w as measured in a graduated buretteat the downstream side of the flow cell and compared tothe results of the automatically recorde d flow readingsfor consistency. No specific procedure was employed tosaturate the samples with wate r prior to the experiment.Instead, the flux was monitored until it had decrea sed toa constant value (usually 5510 h after the start of theexperiment, depending on permeability).

Depending on sample thickness. fluid viscosity andmeasuring time permeabilities down to the range of0.1 nDarcy (IO- m) can be determined with this exper-imental set-up.The evaluation was perform ed according to Darcy slaw:

J, = -! grad P [ms-1

Here J,. denotes volume flow, k the permeabilitycoefficient (m2), ye the fluid viscosity (Pas) and P thefluid pressure (Pa). Depending on the room tem peraturewater viscosity was taken as 9.5-9.09 x 10p4Pas(9.5-9.09 x lO_cP).

D@s i on e x per i m e n t sDiffusion coefficients for methane were measure d onwater-sa turated samples under elevated pore pressureand temperature conditions (3 MP a and 15OC ) with thesame flow cell as in the permeability measurem ents. Thesample plugs w ere first wrap ped with a lead foil (thickness0.25 mm) and then place d into a thin-walled (0.15 mm)coppe r tube. After mounting the arrangement of rocksample and pistons into the flow cell (Figure 1) appli-cation of a confining pressure of 3540M Pa for a shorttime ensured a diffusion-tight seal around the rocksamples. The diffusion experiment was started by intro-ducing a free gas phase of methane into the lower com-partment (stainless-steel porous disk) of the flow cell. Theaqueous phase in the upper compartment was sampledat regular time intervals (l-4 h) and its methane contentdetermined by an automatic analytical unit.

ResultsM i i z e r n l og_vun d geoche m i s t r j ~The cap rock samples show ed significant differences intheir mineralogical and geochem ical composition. Whilethe Jurassic clay-and siltstones of the Haltenbanken Areacontained between 0.3 and 5.5O/~ total organic carbon(TOC) ( T u h k I ) the mostly red coloured claystones fromNorth Germ any were practically devoid of organic m at-ter (TOC < 0.05%).

The ranges o f mineral contents of the two sample setsare listed in Tcrhlr 2. In terms o f mineralogical com-position the samples from Haltenbanken show ed a widervariation than the cap rocks from the North GermanBasin. Quartz contents ranged from 1 6 to 48X, illitecontents between 30 and 60% . and kaolinite and chloriteamounted up to 40% and 20X, respectively. Mostsamples contained traces of mixed-layered minerals(smectite/illite). Pyrite ranged betwe en 0 .5 and 5%.and carbonate-content (predominately siderite) was usu-ally low, exc ept for the samples H6 (I 3%) H 13 (14%)and H9. a massive micritic limestone. Feldspar (plagio-clase) was extremely rare. SEM examination revealedsome heavy minerals (zircon, apatite. rutile).

The red claystones from the North German Basinshowed a rather homogeneous macroscopic and micro-scopic structure as well as a relatively uniform bulk min-eralogical composition. They were dominated by illite(48875%) and quartz (7730%, Trrhlc I ) ) . Kaolinite andchlorite contents amounted to 8% and 10% respectively.SEM analysis revealed carbonate (calcite), feldspar(plagioclase and rarely K-feldspar) and sulfates (barite.anhydrous gypsum) in most of these samples. Hema titewas present in all samples from N orth Germany.Petroplz_bkal proper t ie sS pe c$c s w j i lc e u r e a . Specific surface areas for theclay- and siltstones from both sample sets ranged between1.5 and IO mg- (Tc~hle I) . Exceptionally high values, inexces s of 20mg-. were found for one coarse-grainedsiltstone from the Melke formation containing detritalchlorite (sample H3) and for two red claystones (N5 andN6) from the North G erman Upper R otliegend. SampleH3 had a comparatively high porosity (6.7X, determinedby Hg porosimetry; see below) w herea s its permeabilitywas relatively low. Samples N5 and N6, apart from theirhigher specific surface areas, did not show any excep-tional petrophysical properties. Mercury intrusion yiel-ded porosity values of only 0.7% but the capillarypressure curves (see below) indicated the presence of sig-

Table 2 Mineralogical composition and TOC-content of the caprock samples under investigation

Mineral Haltenbanken Area North Germancomponent [weight %I Basin [weight %I

quartz 16-48 7-30illite 30-60 48-75kaolinite 3-40 3-8chlorite 1-19 O-IOillite/smectite-ml traces -siderite o-14calcite traces o-12pyrite 0.5-5 -feldspar traces tracesTOC 0.3-5.5 < 0.05


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572 Hydrocarbon sealing efficiency of cap rocks: S. Schllimer and B. M. Kroossnificant micropore volume (equivalent pore radii< 2.1 nm). The indirect assessmen t of the porosity basedon the results of the diffusion experiments yielded sig-nificantly higher values (2.5-3%) lending further supportto the presence of an extensive micropore system.

Mercury porosimetryPnrositj,Significant porosity differences were found between thesample sets from the Norw egian Shelf and from northernGermany (Table I). For the relatively homogene ousNorth Germ an red claystones, porosities were mostlybelow 1%. The highest values (around 7%) were mea-sured for the two fanglomerate samples N3 and N4.Due to their higher silt content porosity values of theHaltenbanken samples were larger and ranged usuallybetween 1 and 3%. The highest porosity (6.7%) wasmeasured for sample H3.Porosities were also derived from the results ofdiffusion experiments with the assumption that thediffusing hydrocarbon gas resided exclusively in the porewate r and no sorption took place. These calculationswere performed using a value of 419 ppm for the aqueoussolubility of methane under experimental conditions(150 C, 3 MPa). Figure 5 shows a comparison of theporosities derived from mercury injection and diffusionexperiments for the TOC-free samples from North Ger-many. For samples N3, N8, N 10 and N 11, a relativelygood agreement between the two porosity measurementswas found. For samples N5, N6 and N9 the elevatedporosity values from the diffusion experiments as com-pared to the mercury porosimetry data indicate a sig-nificant m icropore volume not accessible to mercuryintrusion. This result is supported by the shapes of thecorresponding experimental capillary pressure curves (seebelow).

Due to their significant organic matter content theassumption of absence of sorption was not justified forthe Haltenbanken samples. Interpretation of the diffusionresults in terms of porosity was therefore not possible.CupdIary pressure cun~esThe capillary pressure curves fo r all rock samples ana-lysed in this study are shown in Figure 4. The finalintrusion volumes (corresponding to the smallest access-ible equivalent pore radius) lie below 3.5 ,LII g for mostN-German samples. Tw o samples from the Car-boniferous have slightly larger pore volumes (5-7 ~1 gg ).Intrusion volumes for the two fanglomerate samples

N3 NS N6 NB N9 NIO Nli NIL?Sample

Figure5 Porosityvaluesfor shales ro m the North German Basinderived from mercury porosimetry and diffusion experiments

range betwzcn 25 and 30 ALI - . The intrusion volumesof the shale cap rocks from H altenbanken are consistentlyhigher than 4~11g-~ with a maximum value (27/!1 g )found for the coarse-grained siltstone H 3.

Three of the Carboniferous samples (N8. N9. N 12)show distinctly bimodal pore-size distributions (&JW Y4a). The steep slopes at the end sections of the curves(small equivalent radii) indicate the presence of micro-pore volume beyond the resolution of the mercuryporosity measurement.

The capillary pressure curves of the Rotliegend samplesin Figure 4h show, as a common feature, a gradual, steadyincrease with decreasing equivalent pore volume indi-cating a wide pore size distribution. None of the curveshas a distinct inflexion point so that a most prominentpore radius ca nnot be identified. The final intrusion vol-umes lie between 1.5 and 3.5/llg-.

The two fanglomerates (Figure 4~) have sigmoidalcapillary pressure curves with final entry volumesbetween 35 and 3O/llg-. The inflexion points rep-resenting the most prominent pore radii lie between 30and 50 nm.Due to their more heterogeneou s composition the caprock samples from Haltenbanken show a wide variabilityin capillary pressure curves (Figure 4&f). This variabilityis evident even for samples within the same formationtaken at different locations less than 10 km apart.Maximum pore entry volumes range from 10 ,~1gg inthe Tilje formation up to 27 /tlg- in the Melke. Theminimum value was 2.5plg- (sample H15 , Tilje fm.).Both bimodal and monomodal curve shapes are encoun-tered. The extremely wide pore-size distribution indi-cated by curve HlO (Figure 4e) is attributed to the biot-urbations observed in this siltstone sample. A similarfeature. though less distinct, is observed in curve H 9. Formost samples mercury intrusion tends to start graduallyat relatively low pressures, i.e. large equivalent pore radii.The micritic limestone (H5) from the Melke formation(Fi_qurc $f) is a notable exception. Mercury intrusionstarts only at equivalent pore radii below 6&7nm, c or-responding to mercury entry pressures between 20 and30 MPa (29,00043,500 psi).

The standard evaluation of mercury porosimetryexperiments comprises the computation of the totalintrusion volume, porosity, void ratio, smallest and lar-gest equivalent pore radius, m ost frequent pore radius etc.and basic statistics of the pore size distribution. Thisevaluation method is readily applicable for well-shapedcapillary pressure curves like those obtained with thefanglomerates. For the pelitic rocks investigated in thisstudy, however, the limitations of mercury porosimetryare evident. Although practically all samples have ameasurable permeability, indicative of an interconnectedpore network. a significant portion of the pore-size dis-tribution extends in many case s beyond the experimentallimit of 2.1 nm of equivalent pore radius. In the absence ofa distinct inflexion point within the experimental pressurerange a displacement pressure cannot be readily derivedfrom the capillary pressure curves. In Figure 6 this caseis documented for a Rotliegend red claystone sample(N7) where the maximum slope of the curve coincideswith its end point. The displacement pressure resultingfrom the standard evaluation procedure is indicated but,due to the incomplete representation of the pore sizedistribution, it can only be considered as a rough esti-mate. Shales exhibiting mercury capillary pres sure curves


9/16

Hydrocarbon sealing efficiency of cap rocks: S. SchlCimer and B. M. Krooss 573

1.0 10.0 1 0 0 . 0 1000.0Pressure [MPa]

Figure 6 Standard evaluation of mercury intrusion curve for aRotliegend claystone

of this type must probably in any case be classified ashydraulic rather than membrane seals.

Capillary sealing efficiencyWith respec t to the inherent limitations discussed above,th e displu cement pressure (DP) (Figure 2~) should onlybe viewed as an approximation to the capillary sealingefficiency of fine-grained sedimentary rocks. The DPvalues obtained from the evaluation of the mercuryporosity data of the individual cap rock samples are listedin Tuble 1 . For one of the Haltenbanken samples (H15 )and five claystones from northern Germany (N2, N5,N6, N7, N9) the capillary pressure curves did not showdistinct inflexion points within the experimental pressurerange. The corresponding entry pressures for the mostprominent pore radius (PP) were thus greater thanz 3.45 kbar (50,000 psi) and the displacement pressures(LIP) given in Table I must be considered as lower limits.

The Jurassic claystones from Haltenbanken show awide range of displacement pressures (2-170 MPa; 29t&24,600psi) reflecting the large variability in rock fabricand composition. The highest displacement pressure wasfound for a micritic limestone (H5; 170 MPa; 24600psi)and the lowest values (2 MPa; 290psi) for two bio-turbated siltstones (H9, HlO) and a claystone (H7;5 MPa ; 725 psi). Interestingly, this latter sa mple had thelowest permeability of the Haltenbanken sample set(1.9 nDarcy).

Four of the claystone samples from northern Germany(N2, N 7, N 10 and N 11) yielded capillary pressure curves

with intrusion volumes below 2 ~1 g- up to the maximumpressure of 345 MP a (50 ,000 psi). Due to unspecific curveshapes the results obtained for samples NlO and N 11 areconsidered unrealistic. For two samples (N5 and N9)the evaluation yielded mercury displaceme nt pressures inexcess of 100 MPa (14,500 psi) whereas the values for theother samples range between 25 and 61 MPa (3630 and8850 psi).

Displacement pressures computed for the two fan-glomerate samples (N3 and N4;) were 5.8 and 6.6MPa(841 and 957 psi), respectively. Although these values aremuch low er than for the claystones the capillary sealingefficiency of this rock type is still considerable.Tr ans por t par ame te r s

Pe r me ab i l i t y . The permeabilities of the pelitic caprocks investigated were consistently far below the limitof routine permeability measureme nts perform ed in thepetroleum industry (Tuble 1). The Jurassic shales andsiltstones from the Halten-Terrace ranged mostlybetween 5 and 50 nDarcy (I nDarcy = IO- Darcy =lo- m). Substantially higher values, from 1000 up to4300 nDarcy (l-4.3 LIDarcy ) were found only for the twobioturbated siltstones (H9, HlO) and one silty shale (H2).The minimum permeability encountered was slightlybelow 2 nDarcy (sample H7).

For the samples from North Germany the permeabilitymeasureme nts yielded values ranging from below thedetection limit of 0.1 nDarcy (sample N12) up to75 nDarcy for the red claystones and siltstones. The per-meabilities of the two fanglomerate samples N3 and N4lay around 1350 nDarcy.

D@sion parameters . The results of the diffusionmeasureme nts are listed in Table 3 . Thirteen experimentswere performed with water-saturated rock samples at150 C and a fluid pressure of 3 MP a (30 bar). Diffusioncoefficients for the red claystones from the Low er SaxonyBasin ranged between 1 O and 2.6 x IO I ms whereasthe highest diffusion coefficient (4.46 x 10. ms ) wasfound for the fanglomerate sample N3 in accordan ce withits high porosity (6.6% ) and permeability (1370 nDarcy).

Methane diffusion coe fficients for the samples fromHaltenbanken were generally low er than those measure dfor the claystones from N Germany and ranged between1.4x IO- (sample H 8) and 1.14x lO~~mss (sample

Table 3 Results of methane diffusion experiments on cap rocks at 150C and 3 MPa gaspressure

Sample____-_ Depth [ml TOC [% IMethane diffusioncoefficient (150C)

[m* s- I

Bulk rock methaneconcentration (under

experimental conditions)[gCH, mm3 rock]

H4 4184.7 2.49 1.97EE11 38.40H5 4197.5 1.06 4.66E - 11 19.80H6 4209.5 2.82 3.05E - 11 31.80Ha 4043.5 5.44 1.40E-11 29.73HI4 4527.4 0.3 l.l4E-10 17.26N3 4979.9 0.03 4.46E-10 24.96N5 4643.4 0.04 2.45E- 10 16.31N6 4655.1 0.05 2.59E- 10 11.93N8 4053.1 0.05 2.21E-10 5.13N9 3572.2 0.07 1.91EE10 11.52NIO 3394.7 0.02 9.57E-11 1.33Nil 3396.5 0.02 1.60E-10 3.06N12 1549.6 0.03 l.O2E-10 2.58


10/16

574 Hydrocarbon sealing efficiency of cap rocks: S. Schliimer and B. M. KroossHI 3). The low effective diffusion coefficients must beviewed as a consequence of the organic matter content ofthe Jurassic shales. S orption of the methane in thisorganic matter significantly reduces the rate of moleculartransport.

The effective diffusion coefficient is a measure of themolecular mobility of the diffusing species reflecting therate of displacement of individual molecules and, as aconsequence, the rate of advancement of a diffusionfront. The diffusive transmissibility of seal rocks for gasesis not controlled exclusively by the effective diffusioncoefficient but also by the concentration (Cbulk) of thediffusing species in a volume of rock. This concentrationis related to the partial pressure @) of the gas in thereservoir by a partition coefficient (fi) also denoted as gascapacity (Antonov, 1954).

CbulL = / l -p [gCH, m-j rock]The gas capacity is a function of temperature, porosity,

and organic matter content. The bulk rock methane con-centrations under the experimental pressure and tem-perature conditions can be derived from the results ofthe diffusion measurem ents (Krooss and Schae fer, 19 87;Krooss and Leythae user, 1988). The concentrationsfound in this study range from 1.3 up to almost 40gCH,m - rock. i.e. they extend over more than one orderof magnitude. With the experimental gas pressure of3 MP a of pure m ethane and neglecting, as a roughapproximation, the partial pressu re of the wate r andfugacity coefficients, the gas capacities (/3) can be com-puted to range between 0.43 and 13.3 g CH,m-rock/M Pa at the measuring temperature of 150C. Inprinciple, the gas capacity can be used to compute thebulk phase me thane concentration at a given gas partialpressure. How ever, as neither the pressure nor the tem-perature dependence of this parame ter has been estab-lished in detail, the resulting concentration values shouldbe considered tentative.

CorrelationsAttempts to find correlations between the petrophysicaland transport parame ters measure d in this study werelargely unsuccessful. This is only partly due to the limitednumber of samples analysed. Petrophysical propertiesand sealing efficiency are primarily controlled by lith-ology and diagenetic effects, and experience show s thatno simple relationships exist between the various par-ameters. Thus, among the Haltenbanken claystones thesample with the lowest permeability (H7; 1.9nDarcy)has one of the lowest capillary entry pres sures, while itsporosity (3%) and specific surface area (7 m2 g- ) are notexceptional.A distinct correlation was found betw een the TOCvalues of the Haltenbanken shales and the methanediffusion coefficients as shown in Figure 7 . Furthermore. ageneral tendency of permeability decrea se with increasingspecific surface area can be inferred from Figure 8 .How ever, no correlation exists between the diffusioncoefficients and petrophysical parame ters like perme-ability or porosity.Poros i t y -pe rm e ab i l i t ?) re la t ionsh ip sPorosity-permeability relationships are used in basinmodelling and petroleum engineering to estimate the per-

1.0~.120.0 1.0 2.0 3.0 4.0 6.0 6 . 0

TOC %Figure 7 Diffusion coefficients of methane vs the organic carboncontent of shale samples

10000 I.E.17n

z 1000 b II l.E-18

1 E-21

0 . 1 4 1, i 16221 10 100

Specific surface area [mVg]Figure 8 Permeability vs specific surface area for shale cap rocksfrom N Germany and Haltenbanken

meability evolution of sediments with increasing burialdepth and predict the formation properties. As pointedout by Hilfer (199 2) such relationships should be lookedat as a statement about the consolidation process of geo-logical form ations or rock types and not as generalrelations between permeability and bulk porosity

The Kozeny-Carman equation is a widely usedrelationship for permeability estimates (England et al.,1987; Mudford and Best, 1989; Mudford e t cd . , 1991).The equation relates the permeability coefficient (k) tothe porosity (4) and the specific su rface area (s) of theporous medium according to:

k = c,/Ls 4S( 1 - 4,li perm eability coefficient [m]$ porosityS specific surface area [m kg-]

C,b_, KozenyyCarm an constant [mkg-1This equation was originally established for sandstones

and unconsolidated soils. Its validity for tight, con-solidated claystones is speculative and has not been testedin detail.Attempts to represent the permeability data obtainedfor pelitic rocks in this study by the Kozeny-Carmanrelationship were unsuccessful.

In Figure 9 the permeability values of all samples mea-sured in this study a re plotted versus poros ity. In theporosity range up to 3% the permeability coefficientsvary over two orders of magnitude and no general trendcan be observed. Calculated curves superimposed on thisdiagram with a Kozeny-Carman constant of 5 * lOpI3m kg - and different specific su rface areas predict a dras-


11/16

Hydrocarbon sealing efficiency of cap rocks: S. Schlbmer and B. M. Krooss 575

C,,,,,, = 5.0~10 mkg-

IE-17

IE-18

1 -221E-23

0 1 2 3 4 5 6 7Porosity [%]

Figure 9 Permeability vs porosity diagram for pelitic rocks fromHaltenbanken and northern Germany. Kozeny-Carman curvesfrom different specific surface areas are superimposed.

tic decrea se in permeability for porosities below 1%which does not correspond to the experimental results.Qu ar h f i c a t i on q fs e a l ing #c i enc y an d l eak ageprocessesThe focus of the present study was on the test and appli-cation o f experimental methods for the characterisationof the sealing e fficiency of fine-grained elastic sedim entaryrocks. In the following discussion the experimental resultsare used in simple scenarios to demonstrate the pro-cedures for the quantification of hydrocarbon lossesthrough different seal rocks and to compa re the relativeimportance of leakage mechanisms. These predictionscan only be of a very general nature. Ultimately, the dataobtained from this laboratory study should be applied tospecific case histories in the context of integrated basinstudies. This is the only way to take into account thecomplexity of the geological framew ork and the varietyof process es involved during the different stages of basinevolution and reservoir formation.C ap i l l aq~ s e u l i ng q f f i ci er z c y and hy d r ocar bon c ol um nhe i gh t sThe computation of maximum hydrocarbon columnheights from mercury capillary pressure data is an estab-lished procedure discussed in detail by Berg (1975).Schowalter (1979) and Watts (1987). Commonly thecapillary pressure of the hydrocarbon-w ater system(Pc,_) is equated to the buoyancy pressure of a freehydrocarbon column (/z,,,).

Here s is the acceleration due to gravity and p denotesthe density of the formation wate r (p,,,,,) and the hydro-carbon fluid (phc). Due to the capillary pressure exertedby the non-wetting fluids in the reservoir rock, the actualhydrocarbon column heights in reservoirs will usuallybe some what smaller than the values calculated by thisprocedure.Apart from the uncertainties associated with theinterpretation of the experimental capillary pressure

Table 4 Parameters used for the calculation of maximum gasand petroleum (condensate) column heights retained by dif-ferent seal lithologies

0.042 N m (42 dyn cm )0.005Nm (5 dyncm )0.471 N m (471 dyn cm 11095kgm 240kgm 3383kgm 31400

curves, the above procedure involves several unknownswhich may critically influence the hydrocarbon columnprediction. While interfacial tensions (;I) of hydrocarbon-water systems in the temperature and pressure ranges ofinterest have been measure d or can be estimated withsome confidence, the wettability of the seal represents amajor problem. Commonly a wetting angle (H) of zerois assumed . implying a completely water-w et seal. Thisassumption is likely to be wrong for seals containingsignificant amounts of organic matter. Wettability datafor tight shales are practically non-existent. The com-plexity of this problem is increased by potential wett-ability cha nges of seals due to petroleum generation orimpregnation.

Using the above schem e, maximum gas column heightswere calculated based on the DP values indicated in Fig-ure 4 and listed in Table I. The computation was per-formed with the parameters shown in Table 4. Tuhle 5lists the computed maximum gas column heights fo r caprock samples from northern Germany and Halten-banken. The Haltenbanken reservoir fluids are mainlyrich gas condensates (GOR 1500-1800 Std. m3 rn-;Ehrenberg et d. , 1992). Therefo re an additional cal-culation was perform ed for the samples from this areabased on an average petroleum density of 383 kgm and an oil- wate r interfacial tension of 5 IO- N mm . Allcolumn heights were calculated for hydrostaticconditions. In overpressu red reservoirs capillary failureand bleed-off of hydrocarbons will depend to a lesserextent on hydrocarbon column heights.

The capillary pressure data in Tubh 1 and the valuesin Tuble 5 indicate that the capillary sealing efficiency ofthe rocks investigated in this study is generally excellent.Com puted maximum gas column heights for most of theRotliegend and Carboniferous red claystones from theNorth German Basin lie mostly above 600m and eventhe fanglomerate samples can hold gas columns of morethan 80 m. Depending on burial depth and eflective stress,gas pressures required for capillary leakage to occurwould most probably excee d the mechanical strength ofthe lithologies so that the corresponding seals can beclassified as hydraulic.

With the exception of the bioturbated siltstones of theRor Formation the gas sealing capacity of the Hal-tenbanken cap rocks is also excellent. This holds also forthe sealing capac ity for an oil condensate calculatedunder the assumption of a water-wet pore system. Dueto the geologic situation the capillary sealing efficiencyplays only a minor role in the Haltenbanken area. TheCarboniferous and Upper Jurassic shales overlying thereservoir formations are generally overpressure d and acttherefore as pressure seals (Ehrenberg et cd., 1992). Inparticular in the eastern section of the Smmrbukk field a


12/16

576 Hydrocarbon sealing efficiency of cap rocks: S. Schltimer and 6. M. KroossTable 5 Maximum gas and oil column heights computed from displacement pressure (DP) values of cap rocks

Sampleno. Formation

HI MelkeHZ MelkeH3 MelkeH4H5H6H7H8H9HI0HI1HI2

MelkeMelkeMelkeMelkeNotUpper RorLower RorLower RorTilje

HI3 TiljeHI4 TiljeHI5 Tilje

Haltenbankenhomogeneous claystonehomogeneous silty claystonecoarse grained siltstone with detritalchloritehomogeneous claystonemicritc limestone (siderite)homogeneous claystonehomogeneous claystonefinely laminated, TOC-rich clay/siltstonecoarse grained bioturbated siltstonecoarse grained bioturbated siltstoneclaystone with minor interlayers of siltalternate bedding of clay, silt and sand(ripple marks)alternate bedding of quartz-free claylayers and coarse grained siltfine and regularly laminatedsilt/claystoneclaystone with minor interlayers of silt

Nl Upper Rotliegend red claystoneN2 Upper Carboniferous red claystoneN3 Upper Rotliegend fanglomerateN4 Upper Rotliegend fanglomerateN5 Upper Rotliegend red claystoneN6 Upper Rotliegend red claystoneN7 Upper Rotliegend red claystoneN8 Upper Carboniferous red claystoneN9 Upper Carboniferous red claystoneNlO Upper Carboniferous red claystoneNil Upper Carboniferous red claystoneN12 Upper Carboniferous red claystone

Rock type

North German Basin

Depth[ml

3972.4 887 1273973.7 1066 1523976.6 710 1014184.7 1117 1604197.5 2353 3364209.5 1125 1614227.7 68 104043.5 1025 1474145.7 28 44495.8 24 34683.05 986 1414238.4 511 734263.54527.44560 620 89

1482.221837.34979.924990.24643.44655.054796.154053.13572.23394.73396.51549.6

Maximum gas column Maximimu oil columnheight based on DP height based on DP

[ml [ml

236 34652 93

620643

8193

2425706703859

1714--348

strong pressure gradient is directed do wnw ards from the Here , J, 1 is the gas volume flux in (m m- s- ; gas volumeUpper Jurassic Melke formation into the underlying Jur- under subsurface conditions!) through th e top of the layerassic reservoir sections. The investigation of the for- and P, and P2 (in Pa) are the gas phase pressures at themation m echanisms and longevity of pressure seals bottom and at the top, respectively. The gas flux can berepresents another important aspec t in the assessme nt of converted to standard pressure and tempera ture con-sealing efficiency and petroleum reservoir dynamics. ditions using the ideal gas law.Hydrocurbotz leakage by Darq~JlowIn a normally-pressured reservoir, hydrocarbon leakagewill occur when the buoyancy of the hydrocarbon columnexcee ds the capillary pressure of the seal. In over-pressured rese rvoir compartme nts the direction andintensity of fluid flow is controlled by the global pressurefield and buoyancy plays only a minor role. The leakagerate by volume (Darcy ) flow after breakthrough is con-trolled by the permeability coefficient, the fluid viscosityand the pressure gradient. The situation is complicatedby the fact that leakage through an initially water-w et sealwill procee d as a two-pha se flow. Consequently, relativepermeabilities, depending on the saturation state of thepore system ought to be known as a prerequisite for aquantitative description of this proces s.The compressible Darcy flow of a gas phase through aporous layer (seal) o f thickness A.\- (in m) is compute daccording to:

The gas flux after capillary seal failure through a sealof 1OOm was computed with the parameters listed inTable 6. The calculation was perform ed using the dis-placement pressures (DP) for the corresponding rocks(Table I). The compressible flow rates (Table 7) for thisscenario range from 10 up to 10 Std m3m-m.y.-.Average gas contents of commerc ial size reservoirs are inthe range of tens to hundreds of Std mm- withmaximum values of 1500 Stdm3mp (cf. Krooss andLeythaeu ser, 1997). Consequently, gas leakage by com-pressible Darcy flow under the above assumptions willresult in practically instantaneous loss of commerc ial sizereservoir contents on the geologic time scale.

This simple calculation disregards, howe ver, th e two-phase chara cter of the compressible flow gas dismigration

Table 6 Hypothetical scenario used for calculation of Darcy flowof gas and petroleum through a 100 m seal

J E. 2= _k*(P$-Pf)q *2 *P2 - Ask = permeability coefficient [m]q = viscosity [Pa s]

bottom of seal 5000 m (16,404 ft)top of seal 4900 m (16,076 ft)pressure at top 49 MPa (7,107 psi)gas viscosity (rf& 3.00E - 05 Pa. s (3.00E - 02 centipoise)oil viscosity (tf,,,) l.OOE-03 Pa .s (1.0 centipoise)


13/16

Hydrocarbon sealing efficiency of cap rocks: S. Schliimer and B. M. Krooss 577Table 7 Calculated compressible Darcy flow of gas after capillary failure

Sampleno. Formation Depth [ml

HI Melke 3972.4H2 Melke 3973.7H3 Melke 3976.6H4 Melke 4184.7H5 Melke 4197.5H6 Melke 4209.5H7 Melke 4227.7H8 Not 4043.5H9 Upper Ror 4145.7HI0 Lower Ror 4495.8HI1 Lower Ror 4683.1HI2 Tilje 4238.4HI3 Tilje 4263.5HI4 Tilje 4527.4HI5 Tilje 4560.0

Nl Upper Rotliegend 1482.2N2 Upper Carboniferous 1837.3N3 Upper Rotliegend 4979.9N4 Upper Rotliegend 4990.2N5 Upper Rotliegend 4643.4N6 Upper Rotliegend 4655.1N7 Upper Rotliegend 4796.2N8 Upper Carboniferous 4053.1N9 Upper Carboniferous 3572.2NIO Upper Carboniferous 3394.7Nll Upper Carboniferous 3396.5

Gas displacementpressure [MPalHaltenbanken

7.448.945.959.37

19.749.440.578.600.240.208.274.291.985.475.20

North German Basin5.205.390.680.78

20.345.925.897.20

14.380.210.62

PI [MPal P2 IMPal

57.44 49.0 2.22E+0558.94 49.0 4.12E+0755.95 49.0 2.19E+0559.37 49.0 1.73E+0569.74 49.0 3.88E+0659.44 49.0 1.47E+0650.57 49.0 l.O6E+0458.60 49.0 1.22E+0550.24 49.0 1.90E+0750.20 49.0 5.16E+0658.27 49.0 4.31E+0554.29 49.0 2.95E+0551.98 49.0 l.l5E+0555.47 49.0 1.75E+0555.20 49.0 3.12E+05

55.39 49.0 1.81E+0650.68 49.0 8.22E+0650.78 49.0 8.58E+0670.34 49.0 7.07E+0555.92 49.0 1.61 E+0455.89 49.0 1.29E+0657.20 49.0 4.15E+0564.38 49.0 1.66E+0650.21 49.0 1.51E+0450.62 49.0 l.OlE+04

Compressible Darcy flux(@DP) [Std m3 m m.y. 1

process . Furthermore it can be assume d that in manyinstances the capillary pressures required for gas leakageto take place are never reached.

A similar computation was performe d for incom-pressible Darcy flow of oil through the Haltenbankenseal lithologies. The viscosity was estimated as lop3 Pas(Ta ble 6). Due to the lower oil-water interfacial tension(5 x 10-j N rn-), breakthrough pressures for oil are con-siderably lower than for gas. T ab l e 8 shows that thecalculated Darcy fluxes for oil at the corresponding dis-placement and percolation pressures vary by more thanthree ord ers of magnitude.

The above calculations must be considered as tentative.Too many unknowns are still involved and a more precisecalculation must take into account the variation andinterrelationship of numerous parame ters. The validityof Darcys law and a possible transition from volumeflow to molecular transport are issues that require further

Table 8 Calculated Darcy flow of oil after capillary failureIncompressible

flow of oilSample No. Formation PI IMPa] P2 [MPa] [m3m ~2m.y.-]

HIH2H3H7H8H9HI0HI1HI2HI3HI4HI5

HaltenbankenMelke 50.9 49.0 4.1Melke 51.1 49.0 693Melke 51.1 49.0 24Melke 50.1 49.0 0.6

Not 51.0 49.0 2.1Upper Ror 50.0 49.0 1402Lower Ror 50.0 49.0 392Lower Ror 510 49.0 7.5Tilje 50.5 49.0 7.2

Tilje 50.2 49.0 4.2Tilje 50.6 49.0 3.8Tilje 50.6 49.0 6.9

researc h. The pressure situation in the Haltenbankenshow s that permeability and Darcy flow have a muchmore important impact on the sealing efficiency in anindirect way by governing the formation and longevityof pressure seals.

The permeability measurem ents reported in this studywere not performe d under controlled effective stress con-ditions. The axial stress acting upon the samples duringthe experiments was controlled by the degree of tighten-ing of the bolts during assembly of the flow cell and th ethermal expansion of the components during heating.Only very few permeability data for tight lithologies havebeen reported in the literature. Katsube e t a l . (1991)present vertical permeability measurem ents for two shalesamples at effective pressures (BP) ranging up to 60 MP a(600 bar) and derive the following functional relation-ship:

k = k,.exp(-MAP)k, = 118 x IO _ rn

IX= 0.074MPa According to this relationship the permeability of a

shale should decrea se to 0.5 on an effective pressureincrease by 1OM Pa. Assuming that in the experimentsreported here the confining pressure (10-l 5 MPa ; 145(r2200 psi) correspond ed approximately to the axial stress, arough extrapolation to a depth of 5000 m with an effectivestress of 70 MP a (10,100 psi) yields a decre ase in per-meability by a factor of 50-100. Recent measurem entsperform ed in our laboratory support this trend but alsoindicate that slightly different rock types (lithologies)show different effective stress-permeability relationships.


14/16

578 Hydrocarbon sealing efficiency of cap rocks: S. Schliimer and 9. M. KroossEstimation of diffusive lossesUsing the effective diffusion coefficients reported in thiswork the steady-state diffusive flux across a cap rock canbe calculated according to Ficks first law of diffusion:

J = - DctlVChulhThe bulk volume conce ntration of the diffusing s peciesrequired for this calculation can be determined from thegas capacity. It should be noted, howe ver, that gascapacities are temperature-depende nt and not readilyavailable for different temperature ranges.

As a first approximation the gas concentration pervolume of cap rock can be determined from the porosityand the saturation concentration of methane in the porewater under the envisaged subsurface conditions. Meth-ane concentrations in water as a function of pressure,temperature and salinity have been reported in the litera-ture (Haa s, 1978; Battino, 1984).

To comp are the sealing efficiency of the different caprock types examined in this study a simple sce nario waschosen a nd diffusive fluxes through different rock typeswere calculated.The scenario assumes a cap rock of 1OOm thicknessoverlying a gas reservoir filled with methane. The sub-surface fluid pressure (pore pressure) was taken as50 MPa (7,250psi). the temperature as 150 C and thesalinity of the formation wate r as 5000ppm NaC I. Theparame ters used in the calculations are summarised inTable 9.

Bulk rock methane concentration under subsurfaceconditions was calculated from the bulk rock methaneconcentrations (C~~~mc n) determined during thediffusion experiments (3 MP a, 1SOC, fresh water) andthe methane concentrations in wate r under experimental(C;Tt;immt) and subsurface ( Cg~;~~&wa,rr) conditions.respectively:

c rcserwir = ~~~ynent . CtE;;:& watrrbulb (yxrmlentUdterThis computation implies that under both exper-

imental and subsurface conditions the methane residesexclusively in solution in the water-sa turated pore spaceof the cap rock. This assumption is probably not correctfor those samples from the Haltenbanken area containingsignificant amounts of organic matter. Here the exper-imental results indicate considerable sorption of methaneon or in the organic matter which on the one handincreases the gas storage capacity of the rock and on theother hand reduce s the effective diffusion coefficients.Presently practically no information is available on thesorption capacity of organic matter for methane at highpressures and temperature s. With the above assumption

Table 9 Hypothetical cap rock scenario for the computation ofdiffusive lossescap rock thicknessdepth of reservoir/sealboundaryreservoir temperaturehydrostatic pressureCexper,mentCtormatlpnwaterreSBrYO,rsalinityconversion factor (methane)

IOOm (328ft)5000 m (16,404 ft)150C (302F)50 MPa (7,252 psi)419 ppm4610 ppm5000 ppm1.478sd. m3(15C, 1 atm) kg

methane is attributed the same solubility characteristicsin organic matter as in water.

The cumulative amount (Q,,) of methane diflused fromthe reservoir into the cap rock of thickness (I) was com-puted as a function of time (1) according to the relation-ship for diffusive transport in a plane s heet (cf. Krooss 01L/I., 1993a. I993b).

Here C, is the bulk rock methane concentration and Dthe effective diffusion coefficient.

The cumulative diffusive losses were calculated over aperiod of 200 m.y. for the rock samples from N Germanywher eas a shorter diffusion period of 50 m.y. was chosenfor the Haltenbanken samples. The results for the lattershow that diffusive losse s after 50m.y. reach valuesbetween 120 and 520 Std m methane per m of cap rockarea (Figure 10) and lie between 20 and 50 Std m3 rn- during the first 5 m.y.

The computed cumulative diffusive losses for the sam-ples from the N German basin (Figure II) extend over amuch wider range. Apart from the fanglomerate sample(N3) they lie between 100 and 5000 Std m3 methane rn--for a period of 200m.y. The Upper Carboniferous sam-ples N IO. N I I and N 12 have a better sealing efficiencywith respec t to diffusive transport than the samples fromHaltenbanken. Over a period o f 50m.y. the computeddiffusive losses are below or only slightly above 100 Stdm3 methane mm2.

Published data indicate that gas charge s in comme rcialgas fields world-wide range mostly betw een 150 and 1500Std m mm2 (Krooss and Leythaeuser, 1997). With theabove diffusive flux rates pe riods of several tens of millionyears are required to substantially affect the gas contentof a commerc ial gas reservoir.

The rate of diffusive gas losses from reservoirs dependson a number of parame ters like seal thickness, reservoirgeometry, diffusion coefficients, gas capacity of the caprock, pressure and temperature . These need to be evalu-ated individually for a given scenario in the context ofthe evolution of the sedimentary basin.

SummaryThe systematic investigation of the petrophysical andtransport param eters of shale samples from theHaltenbanken area and the North Ge rman Basin has

1000

I0 10 20 30 40 50Time [m.y.]

Figure 10 Cumulative diffusive methane losses calculated for ahypothetical 100 m cap rock with experimental data for differentHaltenbanken shales


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Hydrocarbon sealing efficiency of cap rocks: S. Schlbmer and 6. M. Krooss 579

14 I0 50 10 0 150 200Time [m .y ]

Figure 11 Cumulative diffusive methane losses calculated for ahypothetical 100 m cap rock with experimental data for cap rocksamples from N Germany

provided an initial database for the assessme nt andquantification of the sealing efficiency of pelitic rocks.

The utilisation of the measure d data was exemplifiedby evaluations with respect to capillary pressure as themain retention mechanism and the two essential types oftransport processe s: molecular transpo rt (diffusion) andvolume flow (Darcy flow).

The Carboniferous and Permian (Rotliegend) redshales from northern Germany, due to their very highcapillary entry pressures, can be classified as hydraulicseals. Volume flow through the matrix of these shales willonly play a very minor role and, in consequence, diffusivetransport of gas is considered as the only relevant dis-migration mechanism through these seal lithologies.

The sealing efficiency of the Jurassic shales and silt-stones from Haltenbanken area is somew hat lower thanfor the North German shales. The slightly high er per-meability values reflect the silt content of these samples.The organic matter content results in reduced methanediffusion coefficients and, at the same time, an increasedgas sorption capacity. It must also be expec ted to reducethe capillary sealing efficiency due to partial hydrocarbonwettability.

AcknowledgementsThis work was performed in the context of the GermanNorwe gian Geoscientific Co-operation supported by TheFederal M inistry of Education, Science, Rese arch andTechnology (BMBF; Grant No. ET-6906-B) Den norskestats oljeselskap a.s. (Statoil) and Deutsc he Wissen-schaftliche Gesellschaft fur Erdiil, Erdgas und Kohle e.V.(DGMK ). We are indebted to Dr D. Hanebeck for tech-nical assistance and helpful c omments and to Dr G. Fie-big for fruitful discussions and the contribution of anexample of the numerical modeling of percolationprocesses. We thank Prof. D. H. Welte for his advice andcontinuous interest in this work .

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