OIL AND GAS MIGRATION

Traditionally (Illing, 1933), the process ofpetroleum migration is divided into two parts:• primary migration within the low-permeability

source rocks• secondary migration in permeable carrier

beds and reservoir rocks.It is now recognized that fractured sourcerocks can also act as carrier beds andreservoir rocks so more modern definitions are:

Primary migration of oil and gas is movementwithin the fine-grained portion of the maturesource rock.

Secondary migration is any movement incarrier rocks or reservoir rocks outside thesource rock or movement through fractureswithin the source rock.

Tertiary migration is movement of apreviously formed oil and gas accumulation.

PRIMARY MIGRATION

Primary oil migration within a fine-grainedmature source rock with > 2% total organiccarbon (TOC) occurs initially as a bitumen thatdecomposes to oil and gas and migrates as ahydrocarbon (HC) phase or phases.

The process of HC generation causesexpulsion of petroleum and is often a morepotent mechanism for migration thanmechanical compaction.

Generation and expulsion of light oil,condensate and gas can come from low (<2%) TOC source rocks without a bitumenintermediate. Type III kerogens are the mostlikely source. The migrating phase is HC.

Migration can also occur in aqueous solutionfor the smallest and most soluble molecules(methane, ethane, benzene, toluene).

Migration by diffusion is not significant.

PORE WATER SALINITY

The salinity of pore waters in reservoirstypically increases by 6 to 160 g/L per kmdepth.

The causes of increased salinity are:• salt dissolution (primary)• membrane filtration (secondary)

Seawater salinity is about 35 g/L. Much highersalinities are found in oil field brines.

Typical salinities for giant oil and gasreservoirs are 30 g/L for sandstones and 90g/L for carbonates.

Concentrations of total dissolved solids (TDS)range from 80 to 300 g/L in reservoirs deeperthan 1 km.

SHALE POROSITY

Under hydrostatic conditions, the change inporosities of shales below 30% tends to followtwo distinctive stages.• Stage 1: A linear or exponential decrease in

porosity and density due to mechanicalcompaction down to a subsurfacetemperature of 90 to 110oC

• Stage 2: An unchanging porosity and densityindicating no further compaction.

0 10 20 30 40Porosity (%)

0

1

2

3

4

Depth (km)

Stage 1

Stage 2

POROSITY vs DEPTH

Porosity reductions in stage 1 are mainly dueto mechanical compaction should follow anexponential curve according to classicalconsolidation theory. A more linear trend isoften observed.

The minimum matrix porosity at the top ofstage 2 ranges from 3 to 15% depending onthe clay mineral composition.

Low values correspond to quartz-rich shaleswith little illite or smectite content. Highervalues correspond to clay-rich rocks.

Slight porosity reductions in stage 2 canoriginate from cementation. Small increasescan occur due to hydraulic fracturing.

Porosities of sandstones and carbonates atdepths > 3 km show much greater variabilitythan shales, due to chemical diagenesis,cementation and dissolution.

PORE DIAMETERS

Pores are classified by size:• macropores > 50 nm• mesopores 2 to 50 nm• micropores < 2 nm

Nitrogen desorption (2 to 50 nm) and mercuryintrusion (3 to 300 nm) porosimetry are theprincipal methods available to determine poresize distributions.

Median pore diameters of shale source rocksrange from 5 to 20 nm with a correspondingporosity range of 4 to 15%. The effectivemolecular diameters of some HC products are:

Molecule Diameter (nm)Water 0.30Methane 0.38n-Alkanes 0.47Cyclohexane 0.48Complex aromatics 1-3Asphaltenes 5-10

EXPULSION EFFICIENCY

Shale source rocks act like sieves duringprimary migration. They preferentially releasesmall paraffinic and naphthenic molecules andretain aromatic and asphaltic molecules.

Small HC molecules can migrate through allbut the smallest micropores. Large complexmolecules are retained by small pores.

Expulsion efficiency is a measure of thepercentage of a particular hydrocarbon thatcan escape from the source bed duringprimary migration.

10 15 20 25 30 35Carbon Number

ExpulsionEfficiency %

100

0

PRIMARY MIGRATION MECHANISMS (1)

Migration by DiffusionDiffusion is the spreading of HC as a result ofa concentration gradient. This process leads todispersal rather than accumulation. Diffusionrates in porous media are very low. Methane,the HC with the highest diffusion coefficient, isestimated to take 80 Ma to diffuse a distanceof 1 km.

Migration in Aqueous SolutionMethane is widely distributed in the subsurfacebecause of its solubility in pore fluids and itshigh mobility as a gas phase. Methane has asolubility of about 2500 mg/L at 100oC and 50MPa for a salinity of 150 g/L.

Most other HCs have solubilities less than 50mg/L in the petroleum generation window.

Solubilities decrease with increasing pore fluidTDS, decreasing pressure and temperature,and increasing HC saturation.

PRIMARY MIGRATION MECHANISMS (2)

Migration as Hydrocarbon PhasesMost migration of petroleum takes place byflow of a hydrocarbon liquid or gaseous phasethrough microfractures in the source rock.

Matrix permeabilities for source rocks rangefrom 1 to 10-8 md or 10-15 to 10-23 m2. Theselow values are unlikely to be sufficient formigration. A few microfractures can increasepermeability by many orders of magnitude.

. Consider a 1 kmcube of shale witha permeability of10-23 m2. A singlemicrofracture witha width of lessthan 5 µm would

provide the same

flow. Microfractures with apertures from 5 to500 µm are commonly observed in source

rocks.

MULTI-COMPONENT SYSTEM

For a multi-component system, the bubble-point line divides the liquid stability field fromthe liquid + gas field. The dew-point line dividesthe liquid + gas field from the gas stability field.

The bubble-point (BPL) and dew-point (DPL)lines meet at the critical point (CP).

CB = cricondenbar (max. P).CT = cricondentherm (max. T)

LIQUID

GAS

LIQUID+

GASP

T

CB CP

CT

ISOTHERMAL PRODUCTION

Oil and Gas:Two phase oil and/or gas below CB.Retrograde Gas:Single phase wet gas between the CB and CTwith liquid over part of the P-T path.Gas:Single phase dry gas above CT.P-T Path:Reducing both P-T moves from the gas to gasand condensate to liquid and gas fields.

LIQUID

GAS

LIQUID+

GASP

T

CB CP

CT

GAS-PHASE MIGRATION

As T and P increase, compressed gas candissolve increasing amounts of heavy liquidhydrocarbons.

At depth, the gas-phase can pick upsignificant quantities of liquid hydrocarbon. Asthe gas migrates upwards throughmicrofractures, T and P are reduced andretrograde condensation leads to formation ofan oil-phase.

Gas-phase migration cannot account for giantoil accumulations (such as the Middle East)unless huge volumes of gas have been lost.

Nevertheless, gas-phase migration is areasonable explanation for accumulations inthe Gulf Coast, Niger Delta, Mackenzie Delta,Mahakam Delta and the Po Basin.

OIL-PHASE MIGRATION

Thermal stresses in source rocks (1.5 to 2.5%TOC) generate a continuous bitumen networkwithin the pores from original kerogen. Astemperature increases, the bitumen forms anoil that fills the micropores and is expelled intoadjacent fractures.

Bitumen and oil have lower densities than theoriginal kerogen and a net volume increaseoccurs in the generation process, whichcauses expulsion of oil. Conversion of organicmatter to liquid and gases can cause a netincrease in volume of more than 25%.

Kerogen

Gas

Kerogen Kerogen

Oil andCondensate

Increasing Maturation

SECONDARY MIGRATION

The main force driving secondary migration isthe buoyancy of hydrocarbons. There is atendency for oil and gas to segregate fromaqueous phase liquids because of densitydifferences.

In most cases, the action of gravity leads to acolumn of gas over oil over water. In a fewcases, this does not happen and gravitymigration is restricted by capillary forces.

Capillary pressure is the excess pressurerequired for oil or gas to displace water frompores.

If capillary and buoyancy forces are matched,hydrocarbon can be trapped within a particularlithology. Hydrodynamic traps of this kind arefound in western Canada when gas is founddowndip and below water saturated rocks.

FLUID PRESSURE

Pressures at 1,000 m (1 km) depth andpressure gradients depend on the saturatingfluid the porous medium densities.

GAS OIL WATER BRINE ROCK

P 2,000 8,300 9,800 11,600 22,000 kPa

dPdh

2.0 8.3 9.8 11.6 22.0 kPam

FLUIDS AND PRESSURE

Pressure at any point in a static fluid is equalto the weight of the overlying fluid column:

P = ρρρρg.h = γγγγh

whereP is the fluid pressure [F/L2]ρρρρ is the fluid density [M/L3]

h is the column height [L]γγγγ is the fluid specific weight [F/L3]

The pressure gradient dP/dh is thus thespecific weight , γγγγ=ρρρρg.

Fluid specific gravities in reservoir engineeringcan range from 0.1 for shallow gas to 1.25 forsaturated brines. Hydrocarbon gases rangefrom 0.1 to 0.5, distillates from 0.5 to 0.75, oilsfrom 0.75 to 1.0 and formation water from 1.0to 1.25.

INTERFACIAL TENSION

When a drop of one immiscible fluid isimmersed in another and comes to rest on asolid surface the shape of the resultinginterface is governed by the balance ofadhesive and cohesive forces.

The surface area at the fluid-fluid contact isminimized by the interaction of these forces:

cohesive forces at the fluid-fluid interfaceadhesive forces at the solid-fluid interface

The interfacial tension represents the amountof work needed to create a unit surface area atthe interface. The dimension of work is [FL] sointerfacial tension is [FL/L2] = [FL-1]. The SIunits are N/m or J/m2. Typical values are 0.02to 0.03 N/m for oil-brine and quartz or calcite.

θSOLID SURFACE

WATERAIR

CONTACT ANGLE

The angle between the fluid and solid phasesis called the contact angle. Contact angles arealways measured in the denser fluid phase.

If θ < 900 the fluid is said to “wet” the surface. If

θ > 900 the fluid is said to be “non-wetting”.

adhesion > cohesion =>> “wetting”cohesion > adhesion =>> “non-wetting”

Water “wets” glass, mercury is “non-wetting” ona glass surface.

Interfacial tension creates a curved interfacebetween two immiscible fluids.

θSOLID SURFACE

WATERAIRMERCURY

θ

CAPILLARY RISE

Water rises in a capillary tube diameter, 2r, to aheight, h. The downward force is thus:

W = mg = ρρρρ g.V = ρρρρg.ππππ r2h = ππππ r2.Pc

where Pc = ρ gh is called the capillary pressure.

Pc = Pa - Pw

The downward force of the water is resisted bythe interfacial tension at the contact around thediameter of the tube:

ππππ r2.Pc = 2ππππ r.σσσσwa.cosθθθθwa

Pc = 2σσσσwa.cosθθθθwa /r

2r hPa

Pw

CAPILLARY PRESSURE

The effect of interfacial tension is to create afinite pressure difference between immisciblefluids called the capillary pressure:

Pc = Pnw - Pw

where Pw and Pnw refer to the wetting and non-wetting phases.

Capillary pressure depends on the propertiesof the fluids and solid surfaces, σwa and

cosθwa, and the tube radius, r.

When adhesion > cohesion, adhesive forcesdraw the fluid up the tube until they arebalanced by the weight of the fluid column.

When cohesion > adhesion, cohesive forcesdrag fluid down the tube until they arebalanced by the weight of the head differenceforcing fluid upwards.

WETTABILITY

The wettability of a rock refers to the contactangle for the oil-brine interface.

If θ < 900 the reservoir is said to be “water-wet”.

If θ > 900 the reservoir is said to be “oil-wet”.

In oilfield terminology:

0o - 70o strongly water-wet70o

- 110o intermediate wettability110o - 180o strongly oil-wet

Wettability is affected by factors including

fluid compositionsmineral surface properties

microbial activitytemperature and pressure

WATERFLOOD DISPLACEMENT

WATER WET RESERVOIR

OIL WET RESERVOIR

TYPICAL INTERFACIAL PROPERTIES

Fluid-Fluid System* ContactAngle

(Degrees)

InterfacialTension(N/m)

Air-Mercury 140 0.485Methane-Brine 0 0.072<30oAPI Oil-Brine 0 0.03030o-40o API Oil-Brine 0 0.020>40oAPI Oil-Brine 0 0.015* These results were obtained for a quartz solid surface.

For a pore-throat diameters between 1 mm and1 µm, we obtain the following capillary

pressures:

Fluid-Fluid System Pc

kPaPc

kPaPc

kPaPc

kPaPore-throat dia. (mm) 0.001 0.00 0.1 1.0Methane-Brine 288 28.8 2.88 0.29<30oAPI Oil-Brine 120 12.0 1.20 0.1230o-40o API Oil-Brine 80 8.0 0.80 0.08>40oAPI Oil-Brine 60 6.0 0.60 0.06

OIL-WATER TRANSITION ZONE

At elevations greater than the capillary head,hc, the oil saturation is (1 - Swi). At the OWC,ho, the water saturation is 1. Between ho and hc

the saturations vary continuously through thecapillary transition zone.

WATER

OIL + WATER

OIL

Sw

Pc

hc

ho

INTERFACIAL TENSION CHANGES

Interfacial tensions for oil-water systems rangefrom 0.005 to 0.035 N/m at STP. Withincreasing temperature and pressure, typicalvalues are 0.01 to 0.02 N/m.

Gas-water systems range from 0.03 to 0.07N/m at STP. With increasing temperature andpressure these values to around 0.022 to0.025 N/m.

This means that oil migrates more easily thangas through water-wet rock. The much higherbuoyancy of gas combined with a low viscositygives gas a considerably greater migrationpotential.

At even higher T and P, interfacial tensions foroil-water and gas-water systems approach thesame value (above the critical point for thesystem). The single-phase system exists asgas and condensate.

PORE THROATS

The critical parameter controlling the value ofPc is pore-throat radius. A hydrodynamic trapwill be created at a change in pore-size ifbuoyancy cannot overcome capillary forces.

A small opening in a water-wet reservoirrejects oil (and gas) whereas a small openingin an oil-wet rock rejects water. Most rocks arewater-wet in the subsurface so capillarybarriers to petroleum migration are common.

Capillary pressures in shales with porediameters of 20-50 nm can be massive. Forexample, for a light crude the value of Pc

would be 2400 to 6000 kPa or 24 to 60atmospheres! Natural hydrofracturing limitsthe differential pressure that can be sustained.

Microfractures often provide conduits for oil topass matrix capillary barriers, for example, a500 nm (0.5 mm) microfracture would onlyrequire 480 kPa provided by buoyancy to pass.

JOINTS AND FAULTS

Macrofractures of one kind or another arepervasive in most brittle rocks.

Tensile fractures and normal faults are mostlikely to provide flow conduits because thefractures tend to be more likely to be open.Fault breccias often provide zones of highpermeability.

Reverse faults tend to be less permeable thannormal faults as would be expected from thestress regime responsible for their formation.

Vertical migration of fluids through fracturesystems in both low permeability rocks andreservoir rocks is widely reported in thehydrogeological and petroleum geologyliterature.

Faults can also act as permeability barrierswhere clay gouge or other low permeabilityinfill is produced by shearing.

UNCONFORMITIES

Unconformities are usually associated withsignificant changes in permeabilities and mayrepresent either flow barriers or conduits.

Some petroleum geologists (North, 1985)believe that sub- and intra-Cretaceousunconformities may be the most importantstructural phenomena involved in trapping oiland gas on a worldwide basis.

In western Canada, where the sub-Cretaceousunconformity is overlain by massive sheetsandstones (Mannville), the unconformity canbe a permeable migration pathway.

Unconformities often correspond to periods ofsubaerial erosion when permeability tends tobe enhanced.

A large number of oilfields are related tounconformities including both the Venezuelanand western Canadian heavy oil deposits.

TRAPS AND SEALS

A trap is any part of a reservoir that holdscommercial quantities of oil. The closure of atrap is the vertical distance from the crest orhighest point to the spill point, where the oilspills below the trap into adjacent permeablebeds.

A seal is the low permeability interval abovethe trap.

The gross pay zone in a trap is the distancefrom the top of the accumulation to the lowestpoint on the OWC.

The net pay zone is the part of the gross payinterval that is commercially productive.

SpillPoint

Crest

Closure

Seal

TRAP PROPERTIES

The three most important properties of a trapare:

1. proximity to HC migration pathways2. permeability of the seal3. height of the closure (trap-size).

If a trap is not situated on a migration pathway,it will not accumulate oil. Knowledge ofregional paleoflows is critical to the explorationprocess.

All seals leak. If the seal is too permeable, thetrap the leakage rate may exceed the rate ofmigration and no accumulation will occur.

If the closure is small, the accumulation maynot be commercially viable. Small pools aredifficult to find and expensive to develop.

SEAL PROPERTIES

It is not the matrix permeability but the fracturepermeability of a seal that is critical.

Gas hydrates (permafrost) or regionalevaporites (salt and anhydrite) are the bestseals. Both gas hydrates and evaporites havethe ability to heal fractures over time.

Ductile shales (> 40% clay minerals) are betterseals than more brittle fine-grained rocks. Onlya small percentage of shales have clay-mineralcontents as high as 40%. Most shales arebrittle and are readily fractured on amicroscopic scale. This is sufficient to renderthem ineffective as seals.

Stylolites, formed by pressure solution, can attimes provide effective seals in carbonates.

Asphalt can also act as a seal where oil isdegraded near surface and large HCmolecules block pore-throats.

TRAP INTEGRITY

Structural TrapsIn structural traps, such as simple anticlinaltraps, the buoyant force tends to be directedvertically upwards and approximately normal tobedding. Sedimentary sequences tend toshow vertical changes in lithology and a seriesof silts and shales can provide an effectiveseal.

Stratigraphic TrapsIn a stratigraphic traps, such as a pinchout,the buoyant force is directed up-dip ratherthan vertically. A single thin silty layer in

pinchout can result in loss of seal integrity andno petroleum accumulation will take place.

SECONDARY MIGRATION DISTANCES

About 60% of reservoirs worldwide appear tohave accumulated due to vertical migrationand 40% due to lateral migration from thesource bed. In many cases, both lateral andvertical migration is involved.

Migration distances depend on the size of thebasin in which the oil accumulates.

Basin Type Example % WorldReserves

Foreland Basin and Fold Belts Alberta 56Interior Rift North Sea 23Divergent Margin Gulf Coast 8Active Margin Los Angeles 6Deltas Mackenzie 6Interior Cratonic Sag Williston 1

Vertical migration is more efficient than lateralmigration but less petroleum is collectedbecause traps can only intercept migrationpathways vertically beneath themselves.Lateral migration can drain a larger volume ofsource rock.