Comparison of Light Hydrocarbon Microseepage Mechanisms

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Klusman, R. W., and M. A. Saeed, 1996, Comparison of light hydrocarbonmicroseepage mechanisms, in D. Schumacher and M. A. Abrams, eds.,Hydrocarbon migration and its near-surface expression: AAPG Memoir 66,p. 157168.

Chapter 12

Comparison of Light HydrocarbonMicroseepage Mechanisms

AbstractSurface geochemistry applied to hydrocarbon exploration has gained little acceptance due to the lack of a sat-

isfactory mechanism for vertical migration that is plausible and explains all observations. Acceptance of surfacegeochemistry is also hampered by a widely held belief that reservoirs do not leak. A satisfactory mechanismmust apply in a wide variety of geologic environments and must be verified by laboratory and field observa-tions. Three mechanisms are proposed for vertical migration of light hydrocarbons: diffusion, transport in aque-ous solution, and buoyancy of microbubbles.

Diffusion fails to explain the rapid disappearance of surface anomalies after production from a reservoirbegins. Diffusion is sufficiently rapid to dissipate gas reservoirs quickly in the geologic sense. As a verticalmigration mechanism, it also cannot account for the resolution observed in surface anomalies. Diffusion as amechanism for primary migration of hydrocarbons from source rocks and as a transport mechanism in the near-surface unsaturated zone have been demonstrated. Solubilities of light hydrocarbons in water are low at ambi-ent temperatures, but increase dramatically with increasing temperatures at depth in basins. Transport withwater, either in solution or as a separate hydrocarbon phase, is important in secondary migration. Computermodeling of the process using finite-difference techniques fails to explain the observed resolution and rapid dis-

appearance of surface anomalies.We favor the vertical migration mechanism of displacing water by ascending gas bubbles, that is, the buoy-

ancy of microbubbles. Computer modeling of this mechanism does explain surface observations. The close cor-respondence of surface anomalies with surface projections of a reservoir and the rapidly disappearing surfaceanomalies after the start of production are predicted by this model.

INTRODUCTION

The acceptance and use of surface geochemistry in thepast 60 years has been limited by two major problems.The first is a two-part problem: direct observation of the

microseepage process and development of a defensibletheory about how microseepage occurs. The second prob-lem is the complexity of the secondary reactions occur-ring in light hydrocarbons that are undergoingmicroseepage. These reactions, dominated by oxidationin the upper part of the sedimentary section or in the soilcolumn, can result in many changes and alterations in thenear surface. These manifestations are the basis of indirectsurface exploration techniques (Klusman, 1993).

We focus on the microseepage process itself and themore prominent mechanisms for the transport of light

hydrocarbons from the level of the reservoir to the sur-face. Each proposed mechanism is discussed along withthe evidence for and against it. To be favored, a mecha-nism must apply in most sedimentary environments. Thefavored mechanism must also explain most of the empir-

ical observations that have accumulated during the 60+years of surface exploration.The existence of microseepage is supported by a large

amount of empirical evidence. Foremost are (1) anincrease in nonmethane light hydrocarbons as a reservoiris approached during the mud logging of many wells; (2)an increase in C2/C1, C3/C1, and C4/C1 ratios in soil gasover hydrocarbon reservoirs; (3) sharp lateral changes inthese ratios at the edges of the surface projections ofhydrocarbon reservoirs; (4) the similarity of stable carbonisotopic ratios for methane in soil gases to those found in

157

Ronald W. Klusman

Department of Chemistry and GeochemistryColorado School of MinesGolden, Colorado, U.S.A.

Mahyoub A. Saeed

Faculty of ScienceUniversity of SanaaSanaa, Republic of Yemen


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underlying hydrocarbon reservoirs; and (5) undetectableamounts of14C in soil gas hydrocarbons and secondaryoxidation products, suggesting ancient sources of carbon.

The rate of transport of light hydrocarbons from thereservoir to the surface is hypothesized to be rapid, on theorder of months or a few years, and not requiring signifi-cant geologic time (MacElvain, 1969). Evidence for rapid

transport is primarily from the common observation thata light hydrocarbon soil gas anomaly disappears after ini-tiation of production from a reservoir (Horovitz, 1969).Light hydrocarbons are also observed to increase in a soilgas over pressurized demand gas storage reservoirs(Coleman et al., 1977; Araktingi et al., 1982). Hydro-carbons observed in soil gas over storage reservoirs havestable carbon isotope compositions similar to that of thereservoired gas (Coleman et al., 1977). This frequentobservation of rapid transport may be the most critical fora hypothesized mechanism to predict adequately.

We consider three mechanisms for the migration oflight hydrocarbons from reservoirs to the surface: (1) dif-fusion, (2) transport in solution in ascending water, and(3) buoyancy of microbubbles rising through a water-sat-urated sedimentary column.

MECHANISMS FOR LIGHTHYDROCARBON MICROSEEPAGE

Transport of Hydrocarbons by Diffusion

Diffusion was one of the original mechanisms cited asbeing responsible for microseepage (Stegena, 1961).Diffusion rates through water-saturated pore space have

been calculated but not directly measured in the environ-ment of a hydrocarbon reservoir. Buckley et al. (1958)measured the concentration of dissolved light hydrocar-

bons in formation waters and found that high concentra-tions were localized adjacent to known petroleum andgas reservoirs. This suggests that diffusion controlledtransport has not moved dissolved gases appreciable dis-tances. Diffusion has been directly measured, and a satis-factory theory developed for gas transport in soilcolumns, above the saturated zone.

Stegena (1961) applied Ficks second law to the diffu-sion of hydrocarbons in a sedimentary column. Thechange in concentration with respect to time is

(1)

where D is the coefficient of diffusion and C is the con-centration. is the del operator, a short-hand symbolfor the partial derivative of the variable that follows, inthis case concentration C. This partial derivative is withrespect to the change in concentration in three dimen-sions, x,y,z. Only diffusion in the vertical direction is ofprimary concern in this discussion. We assume that reser-voirs fill instantly, and thereafter gases lost by diffusion

are continually replaced from source rocks. The one-dimensional equation for vertical migration through aplane at the top of the reservoir is

(2)

Integration of equation 2 as shown by Stegena (1961) is

(3)

Equation 3 allows calculation of the concentration of thegas dissolved in the pore water,Ctz, at a depthz, at time t,

betweenz = 0 andz = h. The concentration of the gas inthe reservoir must remain constant at C0.

Stegena (1961) estimated diffusion coefficients formethane to be 1010 to 1012m2/sec. Stegenas calculationindicates that a steady-state concentration of methanewould be achieved at the surface only after hundreds ofmillions of years, even for a relatively shallow reservoir at1000 m. Calculated flux rates for methane to the surfaceare about 2 g/m2/100 m.y. This exceedingly slow trans-port rate contrasts with measured methane flux rates atthe surface in sedimentary basins on the order of0.00.002 g/m2/day (Jakel and Klusman, 1995).

Leythaeuser et al. (1980) measured diffusion rates forlight hydrocarbons in shale cores from a thermallymature, hydrocarbon-rich shale in Greenland. The origi-nal weathered surface was planed off by glaciation, and

the section is presently in permafrost. This suggests thatmicrobial consumption of hydrocarbons was minimal.Ice retreat began about 6000 years ago, allowing hydro-carbon diffusion from the shale to the atmosphere.

Hydrocarbon concentrations in pore ice were constantbelow 8 m depth, which Leythaeuser et al. (1980) definedas C0. The concentration at the surface was assumed to bezero, even though this is not equal to the atmospheric con-centration (Warneck, 1988). Figure 1 shows the distributionof ethane and n-butane concentrations in the rock matrix ofthe core. Initial estimated concentrations C0 from Figure 1were 3.1 ng ethane/g rock and 165 ng n-butane/g rock.The diffusion coefficients were calculated by Leythaeuseret al. (1980) at 6.4 1011 m2/sec for ethane and 3.2 1011

m2/sec for n-butane. Calculated flux rates were about 1g/m2/year for ethane and 0.1 g/m2/year for pentane. Thediffusion rates for light hydrocarbons found byLeythaeuser et al. (1980) are similar in magnitude for theC2C5 hydrocarbons. Extrapolation to methane suggests aflux for methane similar to that of ethane. This flux rate iscomparable to that found by Jakel and Klusman (1995) formethane in sedimentary basins of temperate climates.

Leythaeuser et al. (1982) estimated the time required tofill a gas reservoir and the time required to empty a reser-voir by diffusive loss. They focused on the Harlingen gas

C Cz

h n

n h Dtn z

h

tz

n

n

= +

( )[ ]

=

01

2 2 2

2 1

( )

exp / sin

C

tD

C

z=

2

2

Ct

D C=

158 Klusman and Saeed


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field in The Netherlands. They estimated the half-life ofthis gas field to be 4.5 m.y., by diffusive loss through a caprock, if the gas were not replenished from a source.

Krooss et al. (1992a) reevaluated the calculations ofLeythaeuser et al. (1982) and suggested that the modelwas too simple and did not account for the equilibration

between methane in the gas phase and dissolved

methane in the water-saturated cap rock. Krooss et al.modified equation 3 to calculate only vertical total flux, Q,into a cap rock:

(4)

where h is now the thickness of the cap rock. For t,equation 4 becomes

(5)

To calculate loss of one-half of a reservoired gas, equa-tion 5 was modified by Krooss et al. (1992a) as follows:

(6)

which is rearranged to solve for t1/2:

(7)

Krooss et al. (1992a) gave the cap rock thickness, h, as 390m, with D as 2.12 1010 m2/sec, Q1/2 as 173.9 kgCH4/m2 in the cap rock, and t1/2 as 70 m.y.

This is complicated by two factors. Once the methanepasses the cap rock, it must traverse the overlying sedi-mentary column, which will presumably have a higherpermeability than the cap rock. Therefore, the traverse ofthis part of the section will be more rapid. Also, if theadsorptive sites in the overlying section are not saturated,migrating gas will be removed until adsorbing sites aresaturated. Applied to surface exploration, these factorscan be ignored, if it is assumed the reservoir has existedfor sufficient time for methane and light hydrocarbons to

have traversed the cap rock and the overlying sedimen-tary column and to have saturated the sites capable ofadsorbing methane and light hydrocarbons.

Nelson and Simmons (1992) criticized the Krooss et al.(1992a) calculations, and Krooss et al. (1992b) replied.Nelson and Simmons suggested that the value for D must

be an effective D that incorporates porosity, permeability,and tortuosity terms. They calculated the value for t1/2 to

be 11.5 m.y. for the Harlingen gas reservoir. Nelson andSimmons (1992) also considered the effect of temperatureon the diffusion coefficient and of salinity on the viscosi-

ty of water. With a cap rock temperature of 70C and 3.6wt. % salinity, Nelson and Simmons calculated t1/2 to be4.4 m.y., which was essentially the same as the original 4.5m.y. given by Leythaeuser et al. (1982). Krooss et al.(1992b) reiterated that the original assumptions aboutporosity effects on the value for the diffusion coefficient

were correct and stated that the effect of temperature onD would be addressed in a future publication.

Nelson and Simmons (1995) estimated diffusive lossesof methane and ethane for the McClave gas field on theLas Animas Arch in southeastern Colorado. They includ-ed the effect of temperature on the diffusion coefficientand the effect of salinity on water viscosity. The cap rockis shale, with an estimated porosity of 5%, and the entiremethane volume in the reservoir must be replaced from asource (by catagenesis) every 2.2 m.y. and ethane every5.3 m.y. For a simulated porosity of 10% in the overlying

tQ

hCh D1 2

1 2

0

21

3// /

Q

hC

Dt

h

1 2

0

1 22

1

3/ / +

Q t

hC

Dt

h

( )

02

1

3= +

Q t

hC

Dt

h nDn t h

n

( )exp /

02 2 2

1

2 2 22 1 1= + ( )[ ]=

Chapter 12Comparison of Light Hydrocarbon Microseepage Mechanisms 159

Figure 1Computed (dashed lines) and measured (solidlines) concentration versus depth trends for ethane andn-butane from corehole E in CampanianMaastrichtianshale, Niaqorssuaq, West Greenland. Initial concentra-tions, C0, used for calculation of diffusion coefficients forethane and n-butane were 3.1 and 165.0 ng/g, respectively(indicated by arrows). (From Leythaeuser et al., 1980.Reprinted with permission from Nature, v. 284. Copyright 1980 Macmillan Magazines Limited).


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shale, the replacement time in the McClave field was cal-culated by Nelson and Simmons (1995) as 0.48 m.y. formethane and 1.2 m.y. for ethane.

Krooss et al. (1992a) calculated a total of 347.8 kgCH4/m2 under the cap rock of the Harlingen gas reser-voir. Using the 4.4-m.y. value of Nelson and Simmons(1992) as the half-life of the reservoir and assuming a lin-

ear rate of loss, Nelson and Simmons calculated the aver-age flux through the cap rock as 0.11 mg CH4/m2/day.Nelson and Simmons (1995) calculated fluxes from theMcClave field for methane and ethane. Using the 5%porosity value for the cap rock, the flux for methane was0.007 mg/m2/day and at 10% porosity the flux was 0.03mg/m2/day. The calculated ethane flux was about 0.1that of methane. It should be emphasized that the calcu-lated losses would be a first-order decay process propor-tional to the amount present, and the loss would not belinear with respect to time unless the reservoir weremaintained by secondary migration or catagenesis. Thefluxes of other light hydrocarbons would be less, butwhen the adsorptive capacity of the overlying sedimen-tary column was exceeded, measurable concentrationscould be observed at the surface.

The changes in concentration in a flux chamber at thesurface for methane are within the realm of detection,allowing calculation of flux rates. This requires that themethane reach the surface without being consumed bymethanotrophic bacteria. A single flux determinationwould not be adequate to determine low rates, just as asingle soil gas measurement would not reliably detect asubsurface reservoir. Measured fluxes of 02 mgCH4/m2/day given by Jakel and Klusman (1995) are inthis order of magnitude. We must emphasize thatmethanotrophic bacteria in the soil column do consumemethane and light hydrocarbons. The result is apparentnegative fluxes. That is, methane is removed from theatmosphere as the soil acts as a sink for methane.Negative methane fluxes are commonly determined forsoils of temperate climates, particularly in areas notunderlain by sedimentary basins with hydrocarbonpotential or basins not actively generating hydrocarbonsin the subsurface. There is currently not enough knownabout light hydrocarbon fluxes to effectively use suchmeasurements in surface prospecting. Significant positivefluxes of methane do occur in wet environments, inde-pendent of underlying geology, due to methanogenesis.

Thomas and Clouse (1990a,b,c) determined diffusioncoefficients for heavier hydrocarbons. Using C15 as amodel compound, a diffusion coefficient, D, of 5.7

1011

m2/sec was determined for migration through a kerogenlayer on micritic sediments. Whelan et al. (1984) deter-mined diffusion coefficients for black shales as 1.7 1012,2 1012, 2.6 1012 m2/sec for n-pentane, n-hexane, andn-heptane, respectively. With these lower diffusion coeffi-cients and greater adsorption capacities, we expect thatheavier hydrocarbons will not move at appreciable ratesfrom reservoirs because gasoline-range hydrocarbons areretained for much longer times than are methane andother gaseous hydrocarbons.

The previous discussion suggests that if diffusion werea primary mechanism of vertical migration, it should bepossible to detect elevated concentrations of methane andlight hydrocarbons in soil gases above reservoirs that areundergoing microseepage. That is, diffusion as a trans-port mechanism would not preclude the use of surfacegeochemistry for exploration. However, the response at

the surface to a pressure decrease in a reservoir associat-ed with production would not be detected in the shorttime frame often seen in surface geochemical data(Horovitz, 1969). The effects of nonvertical dispersionmust also be considered, which may not allow an ade-quate explanation of the sharp definition observed formany surface anomalies (Rice, 1986).

Light hydrocarbon transport calculated by equations 3and 4 needs to be incorporated into a computer model ofthe diffusion process in order to assess the interactions ofthe many parameters. Krooss et al. (1992a, b) and Nelsonand Simmons (1992, 1995) calculated the loss of gasthrough the cap rock. Since this gas is no longer recover-able, it is not of economic interest. To test a hypothesis ofdiffusion as a vertical migration mechanism and to applyit to surface geochemical exploration, diffusion throughthe entire sedimentary column must be considered.Layered sedimentary columns must be incorporated foreach modeled layer, with each stratum having a specificvalue for the diffusion coefficient. Also, the change in thediffusion coefficient with temperature in response to thegeothermal gradient and the change in salinity as itaffects the viscosity of pore water must be considered.Furthermore, the equations should be extended to threedimensions, rather than one dimension, to account fordispersion in the horizontal direction and lateral migra-tion of connate water. Only then can a more thoroughunderstanding of the role of diffusion in vertical migra-tion be determined.

Transport of Hydrocarbons by Water

Transport of hydrocarbons by water dissolved inascending water is a second possible mechanism for thetransport of hydrocarbons. The solubilities of hydrocar-

bons and of various petroleum fractions have been mea-sured by Price (1976) and McAuliffe (1979). The aqueoussolubility is relatively constant for ethane throughn-butane, then decreases rapidly with increasing carbonnumber from i-butane through C12; then the rate ofdecrease in solubility is much less for heavier hydrocar-

bons (McAuliffe, 1979). Table 1 lists the solubility of thelight hydrocarbons from methane through n-octane at25C. Water solubilities of individual hydrocarbons andpetroleum fractions increase rapidly with increasing tem-perature (Price, 1976). Figure 2 shows that steeply increas-ing solubilities are particularly evident for the lighteralkanes and lighter distillation fractions.

The removal of hydrocarbons from the ascendingwater must be considered. In the formation where ahydrocarbon is reservoired, the decreased solubility withincreased salinity can be invoked as a removal mecha-



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nism. The well-known salting-out of dissolved molec-ular species estimated using the Setchenow relationshipmay be a suitable mechanism for separating out a hydro-

carbon phase. Price (1976) demonstrated decreasinghydrocarbon solubilities with increasing salinity. Jones(1984) demonstrated secondary migration of hydrocar-

bons by a combination of solution and two-phase trans-port. Solubilization of liquid hydrocarbons in a gas phasewas described by Neglia (1979) and would facilitate sec-ondary migration.

For vertical migration and its application in surfacegeochemistry, hydrodynamics must be considered (Tth,1988; Rostron and Tth, this volume). Connate water inthe sediments, meteoric water added at the margins ofthe basin, and structural water derived from the conver-sion of smectite clays to illite all contribute to the sourceof ascending fluids for two-phase transport. With increas-

ing depth of burial, temperature and pressure increases,resulting in fluid volume increases (Magara, 1978).Spencer (1987) suggested that generation of hydrocar-

bons with increasing depth and temperature adds hydro-carbons to the fluid phase, further increasing pressure.

Bethke (1985) showed a schematic of water flow in asubsiding basin (Figure 3). In the absence of faults, theflow is primarily lateral through permeable layers.Vertical flow becomes more important if the ratio of ver-tical to horizontal path lengths becomes less than the ratioof vertical to horizontal permeabilities. Figure 3 showshorizontal flow velocities at about two orders of magni-tude greater than vertical velocities. If faulting hasoccurred or if high potential gradients are present (bot-

tom, Figure 3), there may be significant vertical flow.Advection and hydrodynamic dispersion must be

considered. In the transport of hydrocarbons by water,advective or bulk vertical transport of hydrocarbons bywater is required to be effective for surface exploration.Evaporative loss may occur as the fluid approaches thesurface, and light hydrocarbons would partition into thegas phase according to Henrys law. The dispersion termwould decrease maximum concentrations and decreaseresolution at the boundaries of anomalies. Tortuosity ofthe sediment and transport by gaseous diffusion above

the water table would also reduce resolution in a surfaceanomaly (Devitt et al., 1987; Krooss et al., 1992b; Nelsonand Simmons, 1992, 1995). Transport of light hydrocar-

bons in the gas phase above the water table is primarilyby diffusion, modified by complex meteorologic and sea-sonal variables (Klusman, 1993).

The transport of a single hydrocarbon molecule due toadvection and dispersion can be written as follows (Bear,1979):

(8)

where Q is the hydrocarbon flux (per liter, or L1), Vthevelocity of water (L/sec), the water content (L), Dt the

Q C V D Ct= [ ] ( )


Table 1Solubility of Light Hydrocarbons in Waterat 25Ca

Solubility

Hydrocarbon (ppm by weight)

Methane 24.4

Ethane 60.4

Propane 62.4n-Butane 61.4

i-Butane 48.9

n-Pentane 38.5

n-Hexane 9.5

n-Heptane 2.93

n-Octane 0.66

aFrom McAuliffe (1979).

Figure 2(a) Aqueous solubilities of second (DF2,132193C), third (DF3, 193232C), fourth (DF4,232316C), and fifth (DF5, 316371C) distillation fractionsof Ghawar Arabian crude oil as a function of temperatureat the pressure of the system. (b) Aqueous solubility ofpentane (C5), hexane (C6), heptane (C7), octane (C8), andnonane (C9) as a function of temperature at the pressureof the system. (From Price, 1976.)


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diffusion coefficient, and C the concentration of dissolvedhydrocarbon. If there are no chemical reactions resultingin production or consumption of the light hydrocarbonsand no adsorption, or if the adsorption sites are alreadysaturated, the mass balance for a dissolved hydrocarbon

becomes

(9)

Substitution of equation 8 into equation 9 gives a hydro-carbon transport equation in water of

(10)

Thomas (1982) solved equation 10 by a finite-differ-ence method, and Saeed (1991) applied it to verticalmigration. The finite-difference method divides the

region of interest into small blocks. Time is divided intosmall steps, which are solved in sequence. The partial dif-ferential equations are replaced by their finite-differenceequivalents, which results in algebraic equations that areapproximations of the original partial differential equa-tions. We determined the concentration of the hydrocar-

bon at the center of the blocks by solving the algebraic

equations using the strongly implicit procedure ofThomas (1982).

Equation 10 was rewritten for each grid point of vol-ume v within the pore solutions as

(11)

Thomas (1982) transformed the two volume integralsof equation 11 to surface integrals by using the Gaussdivergence theorem. If the volume of each block is small,its porosity and density are assumed to be constant, as isthe concentration C of the hydrocarbon. The transforma-

tion to surface integrals gives

(12)

We approximated the dispersive integral in equation12 for two-dimensional flow by considering only fourfaces of the finite difference block:

(13)

To solve the equations, both initial and boundary con-ditions must be defined. An initial hydrocarbon gas con-centration is entered as a constant value at the level of thereservoir, C0. The flux is the sum of the dispersive andadvective fluxes. The dispersive term decreases the flux,and the concentration changes vertically. The computerprogram GASINWAT was modified by Saeed (1991) fromone documented by Healy (1990) for modeling of soluteflow in water. Modifications by Saeed allow varyingporosities and permeabilities in the overlying sedimen-tary column, the compressibility of water, and the solu-

bility change of a hydrocarbon with pressure.Figure 4 shows the calculated dissolved concentration

of light hydrocarbons dissolved in water ascending at1012m/sec for a period of 10,000 years; other input para-meters are given in the figure caption. Little dissolvedhydrocarbons reach the surface in this short period oftime. By increasing the permeabilities of the layers andusing much longer times, appreciable light hydrocarbonsare shown to reach the surface (Figure 5).

The exsolution of the dissolved hydrocarbon into thegaseous phase near the surface is controlled to someextent by Henrys law, although this is a heterogeneousprocess that may result in some degree of gas supersatu-ration in the aqueous phase. Slow evaporation of ground-

D Cnds D Cndsts s

i

t ii

= =1

4

vC

tD Cnds v Cnds

st

s

( )=

C

tdv D Cdv vCdv

v vt

v

( )=

C

tD VCt C= ( )

( )C

t

QC=


Figure 3Calculated compaction-driven flow within abasin cross section. Equipotentials are at intervals of

0.001 MPa (0.01 atm). The flow velocitiesvxand vzare rel-ative to the subsiding medium. (From Bethke, 1985.)


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water would increase the concentration observed in thesoil gas, although this cannot be quantitatively predicted.If the process operated for a long period of time, adsorp-tion sites in the unsaturated sediment and soil would

become saturated. The free soil gas concentration ofhydrocarbons would reach dynamic equilibrium, butvary over short time periods due to meteorologic and sea-sonal parameters (Klusman, 1993). The adsorbed soil gasconcentrations would likely remain more constant than

free soil gas, particularly over the time frame of meteoro-logic variations. Seasonal variations would likely remainsignificant in samples taken in the top few meters(Klusman, 1993).

The upward migration of connate waters associatedwith hydrocarbon reservoirs is supported by heat flowmeasurements. Meyer and McGee (1985) measured high-er temperature gradients over 15 of 22 oil and gas fieldssampled in the Rocky Mountain province. Bodner andSharp (1988) found elevated subsurface temperaturesalong the Wilcox growth fault in the Gulf Coast. Theyproposed upward migration of fluids along the fault,increasing the temperature gradient. Hanor (1987)demonstrated convective transport of connate watersassociated with the Iberia salt dome in Louisiana.

The transport of hydrocarbons by water should allowdetection at the surface and not preclude water transportas a mechanism for vertical migration. The locations ofanomalous free or adsorbed soil gas samples relative to asubsurface reservoir would be determined largely byhydrodynamic flow. This mechanism is not sufficientlyrapid, however, to account for the rapid change in thecharacter of the surface anomaly with initiation of pro-duction. The data of Hanor (1987) suggest flows of a fewmeters per year.

Transport of Hydrocarbons by Buoyancy ofMicrobubbles

Transport of hydrocarbons by buoyancy of microbub-bles occurs when capillary pressure of a microbubble of a

gaseous hydrocarbon exceeds the water displacementpressure of the largest interconnected pores in a cap rock.Watts (1987) classified these as membrane seals. Berg (1975)described membrane seals in stratigraphic traps, andSchowalter (1979) compared the effectiveness of sealsagainst the migration of gas compared to penetration byoil. The threshold displacement pressure required to dis-place water increases as the permeability of the cap rockdecreases (Katz and Coats, 1968). Another variation in thecap rock seal is the hydraulic seal (Watts, 1987). This sealfunctions until there is some degree of overpressure in thereservoir, when the seal opens as a fracture. The scale offracturing is important in the manifestations of the leak-age (Watts, 1987). Microfractures are sufficient to allow

seal penetration by gaseous hydrocarbons. Larger frac-tures and faults may result in upward streaming of two-phase hydrocarbon and water mixtures (Watts, 1987).

MacElvain (1969) was apparently the first to describethe buoyancy of microbubbles in the context of surfaceexploration. He described rates of vertical migration thatwas possibly on the order of several millimeters per sec.The overlying sedimentary column has some capacity foradsorption of light hydrocarbons, as indicated by thermalstripping of well cuttings, but when this capacity isexceeded, the microbubbles move unimpeded in an


Figure 4Calculated concentration of methane, ethane,and n-butane (in ppm by weight) versus depth after 10,000years of migration from a reservoir at 1000 m depth. Thereservoir is overlain by a single lithology with a permeabil-

ity of 103

md, a diffusion coefficient of 1010

m2

/sec, aporosity of 20%, and a water flux rate of 1012 m/sec.(Modified from Saeed, 1991; Klusman, 1993.)

Figure 5Calculated concentration of methane, ethane,andn-decane (in ppm by weight) versus depth after500,000 years of migration from a reservoir at 1000 m

depth. The reservoir is overlain by three lithologies:lithology 1 is 200 m thick and has a permeability of 105

md; lithology 2 is 400 m thick with a permeability of 103

md; and lithology 3 is 400 m thick with a permeability of0.1 md. All lithologies have a porosity of 20%, a diffusioncoefficient of 1010 m2/sec, and a water flux rate of 109

m/sec. (Modified from Saeed, 1991; Klusman, 1993.)


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approximately vertical direction. MacElvain (1969) pro-posed bubbles of a size that would generate significantBrownian motion, which would prevent adsorption. Thisseems unlikely, and does not have to be prevented if theadsorptive capacity of the overlying sediments has beensatisfied by earlier microseepage (Klusman, 1993). Differ-ential adsorption of alkanes by the sedimentary matrix

results in the occasional occurrence of a chromatographiceffect. If the system is in steady-state equilibrium with areservoir of constant composition, the adsorptive siteswill not have any additional chromatographic capacityand additional fractionation will not occur. Also, the sol-ubility of heavier hydrocarbons in the gas phase decreas-es with temperature and pressure, resulting in the lighterhydrocarbons dominating in a soil gas (Price et al., 1983;Price, 1986).

The basic equations describing hydrocarbon gas andwater flow in porous media are the continuity equationsfor each phase. For both gas and water, Darcys law isproportional to the potential gradient of each phase (Teket al., 1966). The velocity of transport for water and gascan be written as follows (Saeed, 1991; Klusman, 1993):

(14)

and

(15)

where Vw and Vg are the velocities of water and gas, Kisthe rock permeability, Kw and Kg are the relative perme-abilities of water and gas, w and g are the viscosities ofwater and gas, and w andg are the water and gas poten-tials, both defined as P + gh. Gas and water relative per-meabilities are related to the degree of gas or water satu-ration. The pressure in the gas phase exceeds that in thewater by the capillary pressure, Pc, and

(16)

where Pg and Pw are the pressures of water and gas,g isthe acceleration due to gravity,g andw are the densitiesof water and gas, and h is the column height. The rela-tionship between capillary pressure and water saturation,s, with respect to time is

(17)

This can be combined with equation 16 to give the rela-tionship between capillary pressure and time:

(18)

The following simultaneous non-linear partial differ-ential equations for both gas and water potentials asdependent variables are obtained:

(19)

and

(20)

where Qg and Qw are gaseous hydrocarbon and waterfluxes and is the water content.

Gas displaces water, so the sum of the fluxes is one,and migration is only considered in the upward direction

because of buoyancy. Equations 19 and 20 modified byCrichlow (1977) allow solution by finite-difference meth-ods. The original computer code written by Tek et al.

(1966) was modified by Saeed (1991) to model hydrocar-bon gas migration by buoyancy of microbubbles.

Figure 6 shows hydrocarbon gas potential with depthover short time periods as calculated by the programGASWATER. The simulated reservoir was at a depth of1000 m and had a single lithology as overburden, a per-meability of 0.001 md, and a porosity of 10%. The reser-voir was overpressured at a total pressure of 3000 psi(20,700 kPa). There were rapid changes in gas potentialabove the reservoir, but not readily discernible at the sur-face.

Figure 7 shows the hydrocarbon gas potential overshort time periods at three different reservoir pressures.As in Figure 6, the simulated reservoir was 1000 m deep

and had a single lithology as overburden, a permeabilityof 0.001 md, and a porosity of 10%. The modeled reser-voir pressures were 1500 psi (10,300 kPa), 2000 psi (13,800kPa), and 3000 psi (20,700 kPa). These pressures areslightly below hydrostatic pressure, just above hydrostat-ic pressure, and well above hydrostatic pressure, respec-tively. Curves A, B, and C on Figure 7 are for a location 10m below the surface. Curves D, E, and F are for a location100 m above the reservoir. Again, only small differencesare noted at the near-surface locations relative to the loca-tion just above the reservoir.

Figure 8 is an expanded view of the upper left cornerof Figure 7, showing only the data for the location 10 m

below the surface. The greater the magnitude of the reser-

voir pressure, the greater the change in gas potential atthe surface in short time intervals. If production were tooccur from the simulated reservoir, rapid changes would

be observed both in the reservoir and at the near-surfacelocation. This is consistent with observations of enhancedleakage discussed in the introduction on pressurechanges in demand gas storage reservoirs.

The plot in Figure 9 shows the calculated change in gaspotential pressure 10 m below the surface for differentsimulated reservoir pressures, again at a depth of 1000 m.If the reservoir pressure were abruptly changed from

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2000 psi (13,800 kPa) to 1500 psi (10,300 kPa), a change ingas potential of 41 kPa would be observed in the near sur-face in 10 years. A change in reservoir pressure from 3000psi (20,700 kPa) to 1500 psi (10,300 kPa) would change thegas potential by 170 kPa in the same time period. The sim-ulated change in gas potential declines relatively rapidly

after 10 years for a low-pressure reservoir and after 40years for a high-pressure reservoir.

Modeling of the buoyancy of microbubbles of gas bySaeed (1991) supports this mechanism as responsible forvertical migration. It satisfies our difficult requirementthat migration be close to vertical, so that anomaliesremain sharply defined at the surface. The simulation ofthis mechanism also predicts the rapid response in gaspotential and in observed soil gas concentration changesat the surface.

Araktingi et al. (1982) described the failure of a faultseal in the Leroy gas storage reservoir in southwesternWyoming. The fault seal failure was intermittent, in directresponse to the reservoir pressure changes. Copious leak-

age was noted at the surface a few years after overpres-suring the reservoir. They described this phenomenon asacting like a check valve, although a more appropriateterm might be pressure relief valve such as on a waterheater. With overpressuring, the fault (valve) opened,allowing copious leakage until the pressure dropped

below the capillary entry pressure. Then the fault (valve)closed again. The transport rate of gas to the surface wason the order of 1000 ft/year (~300 m/year). In this case,the system was acting as a hydraulic seal, using Watts(1987) terminology.

Arp (1992) described pressure-induced leakage fromthe Patrick Draw field in southwestern Wyoming.Produced gas, as well as water, were reinjected into the

field to maintain pressure. Initial gas injection is thought tohave begun about 19601962; there were reports of surfacevegetation die-off by 1980 due to saline water and becauseof anaerobic soils as hydrocarbons displaced oxygen. Thistranslates to a transport rate 250 ft/year (~75 m/year).Large petroleum production increases began in the19731975 period. If the die-off that started in 1980 is relat-ed to the production increase, the transport rate for hydro-carbons and water exceeds 1000 ft/year (~300 m/year).

We must be careful not to interpret these examplesstrictly as buoyancy of microbubbles. The Leroy storagereservoir described by Araktingi et al. (1982) and thePatrick Draw oil field leakage described by Arp (1992)represent atypical flow rates. The leakage from PatrickDraw was certainly two-phase, as evidenced by observa-tions of saline water and extreme concentrations ofhydrocarbons in the soil gas.

CONCLUSIONS

Three mechanisms proposed for vertical migrationand microseepage have been evaluated: diffusion, trans-port by ascending water, and buoyancy of microbubbles.All three mechanisms can produce surface anomalies.


Figure 6Calculated hydrocarbon gas potential versusdepth after 2, 5, 10, and 27 years. A single lithology with apermeability of 0.001 md and a porosity of 10% overliesthe reservoir at 1000 m depth. Reservoir pressure is 3000psi (20,700 kPa). (Modified from Saeed, 1991; Klusman,1993.)

Figure 7Calculated hydrocarbon gas potential versus

time as a function of reservoir gas potential. A singlelithology with a permeability of 0.001 md and a porosity of10% overlies the reservoir at 1000 m depth. Curves A, B,and C (far left) are 10 m below the surface with reservoirpressures of 1500 psi (10,300 kPa), 2000 psi (13,800 kPa),and 3000 psi (20,700 kPa), respectively. Curves D, E, and Fare 100 m above the reservoir with reservoir pressures of1500 psi (10,300 kPa), 2000 psi (13,800 kPa), and 3000 psi(20,700 kPa), respectively. (Modified from Saeed, 1991;Klusman, 1993.)


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Diffusion may be the dominant transport mechanismin the short interval above the water table, but it cannot

be the dominant mechanism through the entire saturatedzone. One major problem is the speed of transport, eventhough Leythaeuser et al. (1982), Krooss et al. (1992a, b),and Nelson and Simmons (1992, 1995) proposed that gasreservoirs are somewhat ephemeral during geologic time.

Other observations not satisfied by a diffusion mecha-nism are (1) close correspondence of a projection of thesubsurface reservoir with the anomaly on the surface, (2)sharp lateral variations that would be blurred if diffusionwere the principal mechanism (Rice, 1986), and most seri-ously, (3) the disappearance of anomalies after produc-tion starts (Horvitz, 1969). The role of diffusion in prima-ry migration remains viable (Thomas and Clouse,1990a,b,c).

The mechanism of vertical transport by dissolution inwater suffers many of the same problems as transport bydiffusion. Significant lateral offset of surface anomalieswould be much more common, and gas anomalies direct-ly above the reservoir would be rare. Dispersion, result-

ing in blurred anomalies, would be the norm, and haloanomalies would be rare. The rapid disappearance of asurface anomaly with initiation of production also wouldnot occur with the water transport mechanism. The roleof water transport in secondary migration is likely amajor factor (Tth, 1988).

Ascending buoyant microbubbles of gaseous hydro-carbons is the third mechanism that was discussed.Modeling by Saeed (1991) supports this as the dominantmechanism for vertical migration and as responsible forsurface anomalies. This was also the conclusion of Price

(1986). This favored mechanism can explain near-verticalmigration in the absence of faulting and normal slowrates of lateral water flow in a basin. It also explainsanomalies that are directly above the surface projection ofreservoirs. Indirect effects such as secondary cementationof part of the sedimentary column result in halo anom-alies due to diversion of microseepage around thecemented chimney produced by oxidation-reductionprocesses (Klusman, 1993). Most importantly, the com-puter simulations of Saeed (1991) predict rapid changesin surface anomalies once production from the reservoirstarts.

AcknowledgmentsSupport was provided to M. A. S. by theU.S. Agency for International Development during part of histenure as a student at the Colorado School of Mines. The man-uscript was improved by the reviews of M. A. Abrams,D. Schumacher, and particularly W. A. Young.

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Figure 8An expanded view of the upper left corner ofFigure 7 showing only the data for the location 10 m

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Comparison of Light Hydrocarbon Microseepage Mechanisms

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