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Effects of episodic fluid flow on hydrocarbon migration in the Newport-Inglewood Fault Zone, Southern California

B. JUNG1, G. GARVEN 2 AND J. R. BOLES3

1Department of Earth Sciences, Uppsala University, Uppsala, Sweden; 2Department of Earth and Ocean Sciences, Tufts

University, Medford, MA, USA; 3Department of Earth Science, University of California, Santa Barbara, CA, USA

ABSTRACT

Fault permeability may vary through time due to tectonic deformations, transients in pore pressure and effective

stress, and mineralization associated with water-rock reactions. Time-varying permeability will affect subsurface

fluid migration rates and patterns of petroleum accumulation in densely faulted sedimentary basins such as those

associated with the borderland basins of Southern California. This study explores the petroleum fluid dynamics of

this migration. As a multiphase flow and petroleum migration case study on the role of faults, computational

models for both episodic and continuous hydrocarbon migration are constructed to investigate large-scale fluid

flow and petroleum accumulation along a northern section of the Newport-Inglewood fault zone in the Los

Angeles basin, Southern California. The numerical code solves the governing equations for oil, water, and heat

transport in heterogeneous and anisotropic geologic cross sections but neglects flow in the third dimension for

practical applications. Our numerical results suggest that fault permeability and fluid pressure fluctuations are cru-

cial factors for distributing hydrocarbon accumulations associated with fault zones, and they also play important

roles in controlling the geologic timing for reservoir filling. Episodic flow appears to enhance hydrocarbon accu-

mulation more strongly by enabling stepwise build-up in oil saturation in adjacent sedimentary formations due to

temporally high pore pressure and high permeability caused by periodic fault rupture. Under assumptions that

fault permeability fluctuate within the range of 1–1000 millidarcys (10�15–10�12 m2) and fault pressures fluctuate within 10–80% of overpressure ratio, the estimated oil volume in the Inglewood oil field (approximately 450 mil-

lion barrels oil equivalent) can be accumulated in about 24 000 years, assuming a seismically induced fluid flow

event occurs every 2000 years. This episodic petroleum migration model could be more geologically important

than a continuous-flow model, when considering the observed patterns of hydrocarbons and seismically active

tectonic setting of the Los Angeles basin.

Key words: episodic fluid flow, fluid flow in faults, multiphase flow in siliciclastic sedimentary basins, petroleum

migration

Received 21 May 2013; accepted 16 October 2013

Corresponding author: Byeongju Jung, Department of Earth Sciences, Uppsala University, Gl227 Geocentrum,

Villav€agen 16B, 753 36 Uppsala, Sweden.

Email: [email protected]. Tel: +46 018 471 2264. Fax: +1 617 627 3584.

Geofluids (2014) 14, 234–250

INTRODUCTION

Large-scale faults in sedimentary basins have become

increasingly studied due to their important role in convey-

ing and compartmentalizing hydrocarbons (Aydin 2000;

Boles et al. 2004; Karlsen & Skeie 2006; Kroeger et al.

2009; Zhang et al. 2009; Gong et al. 2011). The hydro-

mechanical properties of faults in active continental mar-

gins are strongly affected by tectonic deformation, so

considering the fluid dynamics of faults will likely improve

our understanding of petroleum migration (Reynolds &

Lister 1987; Blanpied et al. 1992; Sibson 1994; Appold &

Garven 2000; Yamaguchi et al. 2011). For example, there

is abundant geological evidence, at both macroscopic and

microscopic scales, that faults focus fluid flow over long

periods of time but later are sealed by mechanical compac-

tion and chemical reactions causing mineral precipitation

(Eichhubl & Boles 2000; Caine et al. 2010; Faulkner et al.

2010). The hydrologic activity of fault zones may also

depend highly on earthquakes, which in turn may induce

periodic fluctuations in pore fluid pressure and fault per-

meability (Evans 1992; Sibson 1994). Furthermore, large-

Geofluids (2014) 14, 234–250 doi: 10.1111/gfl.12070

scale fault zones may affect regional hydrocarbon migration

by regulating the spatial distribution of overpressure in the

subsurface (Sperrevik et al. 2002; Fisher et al. 2003; Sork-

habi & Tsuji 2005). Laboratory experiments on fractured

rock show that active shear faults are more permeable than

the adjacent country rock by two to three orders in magni-

tude. These faults then become less permeable when deac-

tivated (Aydin 2000).

The mechanism of recurring fluid pressure build-up, hy-

drofracturing, fluid surge, and fault sealing can also be a

potential means for hydrocarbon migration (Bradley 1975;

Walder & Nur 1984; Mandl & Harkness 1987). For exam-

ple, field observations of brecciated rocks and hydrother-

mal veins from the Stillwater fault zone in Nevada indicate

that petroleum migration was not completed as one single

flow event, but rather accumulation too place over many

episodes of oil flow during the deformation history (Caine

et al. 2010). Geochemical evidence from hydrocarbon con-

densates found in the South China basin also support the

notion that petroleum migration occurs simultaneously

with episodes of hydrothermal fluid flow (Guo et al.

2011).

We further hypothesize that the hydrodynamic effects of

multiphase flow are more effective for long-distance trans-

port, during periods of strong overpressuring associated

with episodes of seismically controlled fluid flow. Episodic

flow associated with large faults may also be more effective

than long-term continuous or steady flow of hydrocarbons,

as might be envisioned for a slowly subsiding sedimentary

basin. To test this hypothesis, we conduct 2D finite ele-

ment simulations for multiphase flow in geologically com-

plex cross sections through a basin. We introduce two

migration scenarios of continuous flow and of episodic

flow, which likely account for the current distribution of

hydrocarbon pools such as the Inglewood oil field. The

continuous models assume constant fault permeability and

fluid pressure throughout the simulation time, while those

conditions are time varying in the episodic models. We first

compared the fluid pressure, subsurface temperature, and

petroleum saturations from these models and then per-

formed sensitivity studies on the fault permeability and the

frequency of episodic flow pulses to understand how these

permeability transients might affect overall hydrocarbon

migration and accumulation patterns in a faulted sedimen-

tary basin.

GEOLOGIC SETTING

The Los Angeles (LA) basin is one of the most prolific

hydrocarbon-producing areas on Earth, and it hosts histor-

ically giant oil fields. From the geological survey, it was

recognized that the upper Miocene formations contain

organic-rich sediments and play an important role as the

primary hydrocarbon source rock. Most of the hydrocar-

bons were thermally matured in the central part of the

basin (the central syncline area) and have migrated to the

edges, which are laterally confined by regional-scale fault

zones (Biddle 1991; Jeffrey et al. 1991). The Newport-

Inglewood fault zone is one of the major regional fault sys-

tems that structurally border the southwestern side of the

LA basin, and numerous hydrocarbon reservoirs are closely

associated with the fault structure (Fig. 1A). In the Ingle-

(A) (B)

Fig. 1. Faults and oil fields in the Los Angeles basin (after Wright 1991): (A) LA basin, (B) Inglewood oil field.

Effects of episodic fluid flow 235

wood oil field located on the northern part of the fault

zone, the main production area exists at the intersection

between the Newport-Inglewood and Sentous faults and is

elongated along the trends of both faults (Fig. 1B). Geo-

chemical indicators and biomarkers also suggest the hydro-

carbons discovered in this area have mostly migrated

approximately 10–15 km from the deep basin center with

minor mixing of indigenous petroleum (Kaplan et al.

2000). Tectonic deformation and subsequent seismic activ-

ity make this region attractive for studying the relationship

between hydrocarbon migration and active fault structures

in young sedimentary basins.

The Newport-Inglewood fault zone consists of a series

of en echelon strike slip faults that were reactivated during

the late Pliocene transpressional deformation (Pasadena

Orogeny) and transformed into more complicated anticline

structures containing normal and reverse faults (Fig. 2).

Hydrocarbon reservoirs exist in multiple sedimentary for-

mations but are more concentrated in Pliocene strata con-

taining a high proportion of sandstone. Many productive

petroleum reservoirs align with the trend of the Newport-

Inglewood fault zone, which extends and merges with the

Central Basin d�ecollement at about 10 km depth (Shaw &

Suppe 1996).

The permeability of these sandstones ranges from 10’s

to 1000’s millidarcys (10�14–10�12 m2) for sandy Plio- cene formations (Hesson & Olilang 1990). The thickness

of sediments in the central syncline is approximately

10 km and becomes gradually thinner toward the north-

ern and southwestern edges of the basin (Blake 1991;

Fig. 3). Figure 4A shows an outcrop of channel-fill sand-

stones (Sespe Formation) in the adjacent Santa Barbara

area. The faults in these rocks are filled with carbonate

mineral precipitates and lithified hydrocarbons, which is

strong evidence that the fault zone provided active chan-

nels for hydrocarbon fluids, but later these were sealed

by subsequent reactions involving diagenetic-hydrother-

mal mineralization as fluids cooled or the pressure rap-

idly dropped (Fig. 4B). Five separate hydrogeologic units

were considered here: middle and pper Miocene, lower

and upper Pliocene, and Pleistocene formations (Fig. 3).

The middle Miocene unit (Topanga Formation) consists

of medium to coarse sandstones with intercalated shale

layers. The upper Miocene sediments (Puente Formation)

are mostly siltstone and silty sandstone with interbedded

pelagic mudstone and shale layers (nodular shales in

some areas) that contain high organic carbon contents

(10–16%). This formation is often considered to be the

primary source rock for petroleum generation (Jeffrey

et al. 1991). The lower Pliocene unit (Repetto forma-

tion) serves as a major reservoir for hydrocarbon accu-

mulation. The Repetto consists of fine to coarse

sandstones with interbedded siltstone and shale layers

that have relatively high permeability of 10–100 md

(10�14–10�13 m2) (Higgins & Chapman 1984). The geology of the upper Pliocene unit (Pico formation) is

very similar to the Repetto formation, consisting of inter-

bedded sandstone and siltstone, but with slightly lower

permeability. The Pleistocene unit (San Pedro formation)

consists of relatively uniform and highly permeable sand

layers interbedded with minor gravel, silt, and shale lay-

ers (Olson 1978).

We propose that north–south transpressional tectonic

stresses pressurized the basin continuously from the late

Pliocene to the present. A coupled mechanism of tec-

tonic loading, pore fluid pressure build-up, fault instabil-

ity, and fluid flow may have induced episodic fluid flow

events (Sibson 1994). Elevated effective stress and pore

pressure by tectonic loading compact the sedimentary

rocks during the interseismic periods, making the fault

zone mechanically unstable. When ruptured, high perme-

ability and low pore pressure temporarily create focused

fluid flow in the fault zone. The fault stays open for a

relatively short period of time due to hydromechanical

compaction as the pore pressure decreases, and then

sealed further by hydrothermal mineral precipitation

(Fig. 5). The continuous tectonic stress and rebuilding of

pore pressure cause this cycle to repeat after the fault

zone becomes sealed. Field observations of petroleum

and carbonate mineral deposits in other siliciclastic faults

suggest an episodic nature of injected fluids (Eichhubl &

Boles 2000; Garden et al. 2001), and these episodic flow

patterns may affect the geohydrologic controls on hydro-

carbon accumulation. We modeled this dynamic aspect of

fault zone to understand its effects on petroleum migra-

tion and entrapment. Fig. 2. Cross section of the Newport-Inglewood fault zone along the tran-

sect X–X′ (courtesy of Plains Exploration and Production Company, 2008).

236 B. JUNG et al.

MULTIPHASE FLOW MODEL

To model petroleum migration in the basin, we need to

predict fluid saturation and pressure for both the wetting

phase (formation water) and nonwetting phase (oil). The

governing equations for multiphase fluid flow can be

derived from the fluid mass conservation equations, as

written by Bear (1972):

(A) (B)

Fig. 4. Outcrop pictures of organic-rich sedimentary rocks in California: (A) channel-fill sandstones in nonmarine Sespe Formation (Oligocene) from Old San

Marcos road, Santa Barbara County, CA, (B) tar-filled fault breccia in Monterey Formation at Arroyo Burro beach, Santa Barbara County, CA.

Fig. 3. Lithostratigraphy of the Los Angeles

basin, modified from Blake (1991).

Effects of episodic fluid flow 237

/ @ðqwSwÞ

@t ¼ �O � ðqwvwÞ þ qwmw ð1Þ

/ @ðqnSnÞ

@t ¼ / @ðqnð1 � SwÞÞ

@t ¼ �O � ðqnvnÞ þ qnmn ð2Þ

where / is the effective porosity of a formation, and S is the saturation of the phase: the subscripts n and w denote

the nonwetting (liquid petroleum) and wetting (water)

phases, respectively. Additionally, q is mass density of the fluid, m is a source/sink term, and v is the Darcy velocity

(specific discharge) of each fluid phase, expressed as fol-

lows:

vw ¼ �kwkðOqw � qwgÞ ð3Þ

vn ¼ �knkðOqn � qngÞ ¼ �knðOqw þ Oqc � qgÞ ð4Þ where k is the intrinsic permeability tensor, p is fluid pres-

sure, g is a gravitational vector (g = (0, 0, �g)), and pc is capillary pressure (pc = pn – pw). The parameter, k, is the mobility coefficient and defined by the ratio of relative per-

meability (kr) and dynamic viscosity (l) as:

kw ¼ krw=lw; kn ¼ krn=ln ð5Þ

After a few steps of algebraic manipulation, the pressure

and saturation equations can be decoupled. If slightly com-

pressible fluids are assumed, the final form of average pres-

sure and saturation equations can be written as follows

(Geiger et al. 2004):

/ct @ �P

@t ¼ O � kfktO�P � 0:5ðkw � knÞOpc�

ðkwqw þ knqnÞggþmt ð6Þ

/ @Sn @t

¼ O � ½fnvt � �kkfOqc þ ðpw � pnÞgg� � mt ¼ 0 ð7Þ

where ct is bulk compressibility of a medium, and mt is a

source/sink term. vt is the sum of water and petroleum

velocites (vt = vw + vn). The average pressure �P is an arith- metic mean of the water and petroleum pressure, and f is a

fractional flow coefficient that is also defined for simplicity:

fw ¼ kw kt

; fn ¼ kn kt

; and �k ¼ kwkn kt

ð8Þ

The first, second, and third terms in the right-hand side

of the pressure equation (Eq. 6) represent advection, capil-

larity, and buoyancy flow terms, respectively.

Conventional multiphase flow equations were decoupled

in terms of average pressure and petroleum saturation.

These equations were solved using the implicit-pressure

explicit-saturation (so called ‘IMPES’) technique (Helmig

1997; Huber & Helmig 2000; Class et al. 2002; Reichen-

berger et al. 2006), a technique that produces solutions

faster than those requiring time-consuming nonlinear itera-

tions. Solutions to the pressure and saturation equations

were computed using a hybrid numerical method called

FEFVM suggested by Geiger et al. (2004, 2006). This

method applies a finite element method (FEM) for com-

puting average pressure and then a finite volume method

(FVM) for computing fluid saturation. A fully upwind for-

mulation and total velocity diminishing (TVD) method

(Harten 1997) were also used for solutions to avoid both

numerical dispersion and spurious oscillation at the satura-

tion front.

Capillary pressure and relative permeability models devel-

oped by van Genuchten (1980) were used for describing

two-phase fluid–solid interaction in the porous media.

The van Genuchten model has been widely used in a

multiphase flow modeling and well known for providing

stable numerical solutions when applying continuous capil-

lary pressure functions for a whole saturation interval.

Stress or temperature dependent parameters were not

included in the numerical formulation.

Petroleum density and viscosity were computed using

empirical equations suggested by Glasø (1980) and Eng-

land et al. (1987). Liquid petroleum density generally

decreases with increasing pressure because the solubility of

gaseous component increases. The dynamic viscosity of oil

Fig. 5. Coupled hydromechanic and hydrother-

mal processes for episodic fluid flow (as known

as fault-valve mechanism), adopted from Sibson

(1994). The parameter and variables: pf is fluid

pressure; s is shear stress along the fault; C is

the cohesive strength of the fault; ls is the sta-

tic coefficient of rock friction, and rn is the nor-

mal stress on the fault.

238 B. JUNG et al.

varies between 5 9 10�4 and 5 9 10�2 Pa�s, and generally decreases exponentially with increasing temperature (Eng-

land et al. 1987). Fluid properties of the formation water

were obtained from a set of state equations proposed by

Phillips et al. (1981, 1983) and Watson et al. (1980),

which consider the effects of temperature, pressure, and

salinity/NaCl concentration on water density.

MODEL CONFIGURATION

The models, in this research, are based on the cross section

in Fig. 2, which illustrates the present geology of the New-

port-Inglewood fault zone and associated oil fields (e.g.,

Inglewood oil field) along the transect X–X′ in Fig. 1B.

This profile, which consists of anticline folds with heavily

faulted rocks, was chosen because it represents the typical

geologic settings of oil reservoirs along the NIFZ. The

numerical grid was discretized into 7655 triangular ele-

ments using a Delaunay triangulation method for detailed

rendering of geological structures (de Berg et al. 2008;

Fig. 6). The Newport-Inglewood fault zone and surround-

ing areas were divided into smaller elements to increase the

resolution of the numerical solution.

Because this model is only two-dimensional, a character-

istic fault length or effective flow field length was intro-

duced for petroleum volume calculation. The total length

of Inglewood Oil Field is about 5 km, so we assume that

20% of the total fault length (Approximately 1 km) in pro-

file is available for petroleum migration. The width of fault

zone in the numerical grid is approximately 50 m. Model

parameters used in the simulations are listed in Table 1.

Permeability and porosity of each hydrogeologic unit were

obtained from several publications (Yerkes 1972; Olson

1978; Higgins & Chapman 1984; Hesson & Olilang

1990; Nishikawa et al. 2009) and chosen within the ranges

considered to be representative for these local formations.

Fault permeability was not available from any local field

measurements, so it was systematically varied or dynami-

cally changed as part of model parameter sensitivity analy-

sis. Anisotropic permeability ratio values of up to 100:1

(kx/kz), typical for a regional-scale flow, were chosen for

most formations except the Pleistocene sediments, which

are known to be the most permeable and yet not fully con-

solidated. A thermal dispersivity a approximately 100 m was assumed for all formations, reflecting the longitudinal

solute dispersivity value for a regional groundwater flow

system (de Marsily 1986; Gelhar et al. 1992). Matrix ther-

mal conductivity values of 3.0 W m�1°C were assigned to most sandstone-dominant units and values of 2.5–

2.8 W m�1°C were assigned to the units having high con- tent of siltstone and interbedded shale (Blackwell & Steele

1989). A specific heat capacity value of 750 J kg�1°C, typi- cal of sandstone and shale, was assigned for all hydrogeo-

logic units and faults (Sabins 1997). Formation of water

salinity in the LA basin usually ranges from 20 000 to

34 000 ppm TDS (Hesson & Olilang 1990; California

Department of Conservation 1992) for most oil fields. The

groundwater salinity was set to 25 000 ppm TDS for the

entire model profile.

Capillary pressure in porous sandstone is generally

<0.1 bar (approximately 0.01 MPa) but may increase to tens of bars in source rocks with clay grain size (Ingebrit-

sen et al. 2006). Capillarity model parameters were chosen

within the range of typical rock types obtained from other

publications (Levorsen 1967; Wendebourg 1994; Bloom-

field et al. 2001). Typically, the capillary pressure of more

permeable formations exhibit lower values, but sharp

increases occur near the irreducible water saturation point

(Swr). The sum of water and petroleum relative permeabil-

ity is usually less than one when both phases are mobile.

Initially, hydrostatic conditions and conductive thermal

profile were assumed throughout the basin. The levels of

overpressure were chosen considering that the pore pres-

sure in the Southern California faults may approach

lithostatic pressure due to mechanical compaction (Gra-

tier et al. 2002, 2003). The values of overpressure ratio,

fault permeability, and the period of episodic flow pulses

are presented in Table 2. The over pressure ratio (k*) in a sedimentary basin can be defined as follows (Wang

et al. 2006)

Fig. 6. Model numerical grid, boundary conditions and hydrostratigraphy

of the Newport-Inglewood fault zone based on the cross section along the

transect X–X’ (Fig. 1b). The upper margin is the prescribed pressure head

of 200 m and the isothermal boundary condition of 4°C. The left and right

margins of the grid were assigned to be hydrostatic for pressure and ther-

mally insulated (no flow) for heat. The bottom margin were assigned as no

flow and a constant temperature of 160°C. Overpressure is applied to the

right end of the fault boundary (marked as a white arrow) as a prescribed

pressure condition, and the petroleum saturation at this boundary is con-

stant (Sn = 0.6).

Effects of episodic fluid flow 239

k� ¼ P � PF PL � PF

� 100 ð9Þ

where P is pore fluid pressure in the formation, PF is

hydrostatic pressure, and PL is lithostatic pressure. Porosity

of the fault also changes dynamically in the range of 0.1–

0.3, accompanying with the permeability variation.

In middle Miocene to early Pleistocene, the basin is still

under a shallow marine environment (Wright 1991), so

the prescribed pressure head of 200 m and the isothermal

boundary condition of 4°C were assigned to the top boundary of the grid. The temperature value was chosen

within the ranges of estimated Miocene shallow seawater

temperature (0–6°C) (Zachos et al. 2001). Boundary con- ditions along the bottom margin of the grid were

assigned as no fluid flow (impermeable) and a constant

temperature of 160°C, based on geothermal gradients reported in this area of 35–40°C km�1 (Higgins & Chap- man 1984; Jeffrey et al. 1991). The left and right mar-

gins of the grid were assigned to be hydrostatic for

pressure and thermally insulated for heat. Petroleum was

injected through the fault boundary at the right boundary

(white arrow in Fig. 6), and this condition is physically

possible only when we assume that most of petroleum

was generated in the deep basin center and migrated

through the fault zone.

CONTINUOUS FLOW MODEL

First, we considered a continuous hydrocarbon migration

scenario through the Newport-Inglewood fault zone,

assuming a slightly overpressured sedimentary basin envi-

ronment with constant fault zone permeability. The level

of overpressure at the fault boundary (marked as a white

arrow in Fig. 6) was held constant during the simulation,

and the fault zone was considered as a channel for releas-

ing overpressure of the basin center as well as a conduit for

petroleum migration. For Model 1, the vertical fault per-

meability kz was set to 10 md (10 �14 m2), which is within

the range of kx for the Pliocene unit and higher than that

of Upper Miocene unit. The permeability value was

inferred from the fact that a fault zone may be more per-

meable than its host rock, especially when the fault was

ruptured by shear stresses and brecciated to include sur-

rounding rocks (Aydin 2000). The change of fault perme-

ability during deformation depends on fault rock clay

content and burial history. Laboratory experimental data

show permeability increasing over 2–4 orders of magnitude

(Fisher & Knipe 2001).

Fluid pressure gradients in a compacting sedimentary

basin usually vary between hydrostatic (approximately

10.1 MPa km�1) and lithostatic pressure (approximately 23.3 MPa km�1), and the values used in the simulations

Table 1 Hydrogeologic model parameters.

Parameter Topanga Puente Repetto Pico San Pedro NIFZ

kx, Horizontal permeability (md) 3.2 0.13 18 50 50 1–1000* kx/kz, Anisotropy 100 100 100 100 100 0.1 /, Porosity 0.16 0.17 0.23 0.33 0.30 0.20 ct, Bulk compressibility (Pa

�1) 1 9 10�10 3 9 10�9 1 9 10�10 1 9 10�10 1 9 10�10 3 9 10�9

e, Thermal dispersivity (m) 100 100 100 100 100 100 k, Bulk thermal conductivity (W m�1°C) 3.0 2.5 2.7 2.8 2.8 3.0 c, Specific heat of matrix (J kg�1 °C) 750 750 750 750 750 750 a, van Genuchten coefficient (m�1) 3.0 9 10�4 4.0 9 10�4 2.5 9 10�3 2.0 9 10�3 2.0 9 10�3 1.0 9 10�2

n, van Genuchten coefficient 5.0 4.0 6.0 4.5 4.3 8.0 Swr, Irreducible wetting phase saturation (%) 10 18 12 12 12 12 Snr, Irreducible nonwetting phase saturation (%) 6 10 7 7 7 3

*Fault zone permeabilities are varied depending on model settings described in Table 2. Permeability and porosity values were selected within the ranges from a technical report written by the California Department of Conservation (1991) and unpublished data from Plains Exploration and Production Company. 1 md = 10�15 m2. Capillarity model parameters are obtained from publications (see the text).

Table 2 Petroleum migration scenarios for the Newport-Inglewood fault zone.

Model Scenario Overpressure ratio (%) Fault permeability (md)* Period of fluid pulse (years) Petroleum saturation

1 Continuous 10 10 0.6 2 Continuous 10 5 0.6

3 Continuous 10 20 0.6 4 Continuous 10 50 0.6 5 Episodic 10–80 1–1000 3000 0.6 6 Episodic 10–80 1–1000 2000 0.6 7 Episodic 10–80 1–1000 1000 0.6 8 Episodic 10–80 1–1000 500 0.6

*1 md = 10�15 m2.

240 B. JUNG et al.

were selected based on the current LA basin fluid pressure

gradient of 9.9–12.6 MPa km�1 (Berry 1973; McCulloh 1979). These values can be converted to �1.5 to 19.0% in overpressure ratio. These relatively low-pressure gradients,

despite the high subsidence and sedimentation rates, seem

to originate from the high content of coarse-grained sedi-

ments that can dissipate pressure very effectively in the LA

basin (Hayba & Bethke 1995).

We assumed the whole domain was initially hydrostatic,

and then, the lower right end of the fault on the boundary

of the mesh (marked by the white arrow in Fig. 6) was set

to 10% overpressure. Petroleum saturation at the inlet of

the fault zone was maintained as a constant value of 0.6,

which is taken from the average value of Miocene strata in

the Inglewood oil field (California Department of Conser-

vation 1992).

Figure 7 illustrates the pore pressure change in terms of

hydraulic head (h) of the continuous flow model, assuming

a constant fault permeability of 10 md (10�14 m2) and overpressure ratio of 10% during the whole simulation time

(Model 1). The overpressured areas are sustained in the

lower part of the fault zone and the Miocene formations,

but the Pliocene and Pleistocene formations remain largely

hydrostatic (colored in white). The high pore fluid pressure

change is shown in the lower part of the fault. High fluid

pressure in the fault zone is confined in the Upper Mio-

cene formation due to its low permeability. The pressure

pattern reaches the equilibrium state approximately after

40 000 years. Subsurface temperature under the continu-

ous flow model displays dominantly conductive transport

patterns with nearly horizontal isotherms, except for a

slight elevation along the lower part of the fault zone

(Fig. 8A). Elevated temperatures are the result of upward

fluid flow into the fault zone, and contrast in thermal con-

ductivity. The petroleum velocity distribution of the

domain (Fig. 8B) shows that high velocity (approximately

0.2 m year�1) area appears at the lower part of the fault zone, and it gradually decreases moving up along the fault.

The petroleum velocity at the upper part of the fault is

<0.03 m year�1. Petroleum migrates mainly through the fault zone, and

the upper Miocene formation provides an effective seal for

the migration (Fig. 9A). Highly saturated areas (warmer

color) are found in the boundaries between the fault zone

and the upper Miocene formation because petroleum dis-

charge away from the fault is retarded by the permeability

contrast. Petroleum continues to rise due to buoyancy and

saturates the tributary fault structures such as the Sentous

fault before smearing into the Pliocene formation near the

fault zone, and eventually vents on the sea floor (Fig. 9C,

D).

EFFECT OF FAULT PERMEABILITY

Effects of fault zone permeability on petroleum distribu-

tion were investigated by comparing four continuous

flow models (Models 1–4). The parameters assumed are

tabulated in Table 2. For each model scenario, the per-

meability and pore pressure in the fault zone are assumed

to be constant. We also compared total accumulation

time required to reach the current estimate of total oil

reserve in the Inglewood oil field: approximately 450

million barrels of oil equivalent (MMBOE = 106 barrels) (California Department of Conservation 1992). The total

petroleum volume in a unit of barrel of oil equivalent

(BOE), computed to provide a base of comparison, was

obtained by multiplying petroleum saturation, porosity,

and characteristic length (1 km) for considering the vol-

ume as a three-dimensional domain. The total petroleum

volume within the domain can be calculated using petro-

leum saturation, porosity, finite elemental area, and char-

acteristic length:

PV ¼ XN i¼1

Sn/Ai

! � Lc ð10Þ

where PV is the total petroleum volume at a specified time

step, N the number of finite elements, Sn the petroleum

saturation, / is porosity, Ai is the area of the i-th finite ele- ment, and Lc the characteristic length.

The temporal variation of total petroleum volume of

four continuous models are depicted for showing the rela-

tionship of fault permeability and flow simulation time

required for the total volume of 450 million barrels

Fig. 7. Hydraulic head change (Dh = h – h0, h0 is hydrostatic pressure) of

the Newport-Inglewood fault zone applied with the continuous petroleum

migration model having constant fault zone permeability of 10 md

(10�14 m2) (Model 1) at 100 000 years after starting simulation. Overpres- sure appears along the fault zone. The domain was initially hydrostatic and

then the 10% overpressure was applied at the lower end of the fault

boundary. Numbers are in meter.

Effects of episodic fluid flow 241

(Fig. 10). Not surprisingly, the results indicate that higher

fault permeability results in faster accumulation. For exam-

ple, the reservoir takes about 62 000 years to fill when the

fault permeability is 10 md (10�14 m2), but this time per- iod reduces to about 34 000 years when the permeability

increases to 50 md. It is also worth noting that the filling

time increases with decreasing fault permeability almost in

linear proportion. The spatial patterns of petroleum satura-

tion are also affected significantly by fault permeability.

Figure 11 shows petroleum saturations for Models 1–4

when the total volume is equal to 450 million barrels. In

the high fault permeability model (Model 4, Fig. 11D),

petroleum migrates more vigorously laterally to invade

adjacent formations through fingering and channeling

(A) (B)

Fig. 8. (A) Subsurface temperature (°C) and (B)

petroleum velocity of the fault zone (Model 1)

at 100 000 years after starting simulation. The

top margin of the grid was set as the isothermal

boundary condition of 4°C, and the bottom

margin were assigned as a constant tempera-

ture of 160°C, based on geothermal gradients

reported in this area of 35–40°C km�1. The left and right sides were assumed to be thermally

insulated for heat.

(A) (B)

Fig. 9. Evolution of petroleum saturation for

Model 1 at (A) 40 000 years, (B) 60 000 years,

simulation time showing the advancement of

hydrocarbons through the fault zone. Petroleum

invades into the upper Miocene units because

of the relatively high fluid pressure in the lower

part of the fault. The outline of this magnified

area is marked with dashed lines in Fig. 6.

242 B. JUNG et al.

effects and accumulates significantly enhanced pools in the

Pliocene sediments compared with that of low permeabil-

ity cases. In the low permeability model (Fig. 11A, Model

2), however, accumulation tends to be more abundant in

the upper Miocene sediments and less in the Pliocene

unit.

Fig. 10. Effect of fault permeability on flow

duration needed to accumulate the current

known volume of petroleum in the Inglewood

oil field (1 MMBOE = 106 barrels). Flow dura-

tion assumes that 20% of the total fault length

in transverse is available for petroleum migra-

tion and therefore characteristic or effective

flow length of about 1 km.

(A) (B)

Fig. 11. Comparison of continuous flow models

showing the effects of fault permeability on

petroleum migration and distribution, indicated

by saturation. Numbers in parenthesis indicate

times needed for accumulating total oil reverse

in Inglewood field (see Fig. 10).

Effects of episodic fluid flow 243

EPISODIC FLOW MODEL

Models 5 through 8 were designed to investigate the

effects of episodic fluid flow on petroleum migration,

based on a fault-valve mechanism (Wright 1991), so a

repeating pattern of changing fault permeability and pore

fluid pressure was assigned (Fig. 12). A sharp increase in

permeability from k = 1 to 1000 md (10�15 to 10�12 m2) denotes fault rupturing caused by tectonic stresses or due

to hydrofracturing by fluid pressure accumulation (Fisher

& Knipe 2001). Elevated fault permeability and accompa-

nied focused fluid flow are, however, considered to be

short-lived (<100 years) events (Sibson 1994), so the fault will be closed hydromechanically as the pore pressure

decreases and will be assumed to sealed by mineral precipi-

tation (Dieterich & Kilgore 1996; Scholz 2002; Johnson

& Jia 2005). Recent field measurements of time-varying

permeability in faults after large earthquakes also suggest

that transient fluid pulses play a major role for water circu-

lation in deep fault zones (Xue et al. 2013).

To simulate these sealing effects, the fault zone perme-

ability was decreased from 1000 to 10 md during the first

100 years after rupturing, and then, it continued to be

reduced to 1 md until the next pulse occurs 2000 years

later. We assumed that the hydromechanical compaction

causing the first stage of permeability drop is abrupt and

much faster than the second stage of drop dominated by

hydrothermal precipitation.

We also assume that the fault ruptured at overpressure

ratio of 80%, and pore fluid pressure dropped to 10% over-

pressure level for the episodic flow model. The fluid pressure

gradually builds back up to 80% during the sealing period.

Qualitative behavior of these fluctuating pore pressure pat-

terns was first suggested by Sibson (see review by Roberts &

Nunn 1995), and the pressure value at the fault rupture was

chosen from work by Gratier et al. (2003) and Appold et al.

(2007). Petrologic evidence of multiple pulses of petroleum

flow in fault zones is reported in publications that deal with

Neogene basins in southern California (Boles & Ramseyer

1987; Eichhubl & Boles 2000; Perez & Boles 2007), but

there are a lack of articles providing a quantitative estimation

of possible flow duration. In this study, the period of epi-

sodic flow pulse was chosen within the range of 500–

2000 years based on Myers’s research on the Puente Hill

blind fault in the LA basin (Myers et al. 2003), where he

estimated the recurrence period of earthquakes in this fault

zone to be approximately 1700–3200 years, assuming a

Richter magnitude of M = 6.0–7.5. We assume that earth- quakes in that range could impose significant hydromechan-

ical impacts on the adjacent aquifers.

Fig. 12. Fault permeability and pore fluid pres-

sure settings for the episodic flow model (Model

6). Fault permeability changes applied to the

whole fault zone, and pore pressure changes

applied to the end of the fault on the boundary

elements (marked by the white arrow in Fig. 6)

244 B. JUNG et al.

When the fault zone is sealed, pore fluid pressure builds

up in the lower part of the fault so it cannot reach the upper

formations due to the low fault permeability (Fig. 13A).

After the fault is open, previously accumulated high pressure

is released, and a temporary focus of fluid flow is created in

the fault zone (Fig. 13B). The released overpressure per-

vades the Miocene formations and the center of the anticline

structure. This strong and episodic pressure anomaly may

act as a strong transient driving force for both groundwater

and petroleum. Furthermore, a subsurface heat anomaly is

also detected along the fault zone due to the increased flow

rate and heat advection (Fig. 14). Temperature elevation in

the fault zone can facilitate the petroleum migration by

decreasing viscosity of the fluid. However, the heat anomaly

disappears when the fault is sealed, and isotherms become

horizontal and conductive.

The pattern of petroleum migration in the early stages is

similar to that of continuous migration, which mostly fol-

lows the fault surface (Fig. 15A), but some distinctive and

different patterns appear in later stages. In the episodic

model, petroleum migration seems to be more dispersed

than in the continuous model and accumulates in broader

areas in the middle of the shallow Pliocene sediments.

Petroleum migrates from the fault structures themselves

and extends into the adjacent sedimentary formations.

Effective spreading of petroleum to the adjacent rocks is

due to the high permeability, Darcy flow rates, and fluid

pressure concentrated in this area during the episodic flow

events. Especially, the high fluid pressure facilitates petro-

leum to overcome entry pressure of reservoir rocks sur-

rounding the fault zone.

EFFECT OF EPISODIC FLOW FREQUENCY

To further investigate the effect of frequency of episodic

fluid flow on petroleum accumulation, the temporal varia-

tion of total petroleum volumes for Models 5 to 8 can be

compared graphically (Fig. 16). The total volume of petro-

(A) (B)

Fig. 13. Hydraulic head change (Δh = h – h0) for the episodic flow model (Model 6): (A) just

before the fault opening due to fault rupture,

and (B) 50 years after the fault opening. h0 is

the hydrostatic pressure. Numbers are in meter.

(A) (B)

Fig. 14. Subsurface temperature for the epi-

sodic flow model (Model 6): (A) before the fault

opening, and (B) 50 years after the fault open.

Effects of episodic fluid flow 245

leum increases with flow frequency. If we set the known

450 million barrels as the comparison base, the flow model

with a shorter period of episodic flow pulses reaches the

base faster than the model with a longer period. For exam-

ple, it takes approximately 5700 years if the period of epi-

sodic pulse is 500 years (Model 8) but takes more than

24 100 years if the period is 3000 years (Model 5). Petro-

leum distributions of Models 5 to 8 at the comparison

base were compared in Fig. 17. The overall patterns of

petroleum distributions from four models look similar.

(A) (B)

Fig. 15. Evolution of petroleum saturation for

the episodic flow model (Model 6) at four time

steps.

Fig. 16. Comparison of total petroleum volume

changes of episodic flow models, showing the

effect of fault permeability on recharging (fill-

ing) times needed to accumulate the observed

volume of total oil reserve in the Inglewood oil

field. Filling times (durations) assume that only

20% of the fault zone is available for petroleum

migration along the length of the oil field.

246 B. JUNG et al.

They all caused significant accumulations in the Pliocene

unit and channeled flow in the middle Miocene unit, but

the shorter period scenario (Model 8, Fig. 17D) enables

more pervasive accumulations in the center of the Pliocene

unit, in the Sentous fault, and in the upper part of the

Newport-Inglewood fault zone. It also caused relatively

smaller intrusion into the Middle Miocene unit, which

probably means that the episodic migration having a

shorter period is more active in transferring petroleum

upward because the fault zone is open more frequently

and assumed to be sealed for less time.

The episodic flow model having the fault k range of 1–

1000 md (10�15 to 10�12 m2) and a pulse interval of 3000 years (Model 5) can be compared with a continuous

model (Model 4) having k values of 50 md to demonstrate

differences between continuous and episodic flow models.

These two cases were selected because their simulation

times required for fill the reservoir were most similar

although the pattern of the driving force is different. The

episodic model (Model 5) takes 24 100 years to accumu-

late the petroleum at the level of comparison point

(approximately 450 million barrels). This value is faster

than the elapsed time of the continuous model, which is

34 000 years, having fault permeability of 50 md. When

we consider the relatively short sum of open fault duration

(<1400 years) in Model 5, it could be said that the epi- sodic flow can drive migration of petroleum more effi-

ciently compared to the continuous models with constant

fault permeability higher than 50 md.

For the given amount of total petroleum volume, epi-

sodic fault pressure-driven migration generates broader and

more highly saturated petroleum accumulations in the Pli-

ocene sediments and also showed more dispersed patterns

in the Middle Miocene unit. On the other hand, the con-

tinuous migration made relatively low-saturated accumula-

tions simply following the fault structures. Petroleum in

the continuous model also tends to stay in the lower part

of the fault zone and rise slowly by the forces of buoyancy.

CONCLUSIONS

To understand the dynamics of petroleum migration in

active margin basins, both continuous and episodic fluid

migration models were constructed for the Newport-Ingle-

wood fault zone in the Los Angeles basin. The effects of

time-varying fault permeability on hydrocarbon accumula-

tion rate and pattern are also quantitatively investigated

using multiphase numerical modeling.

In continuous flow models, the petroleum migration

rate in the fault zone ranges 0.03–0.2 m year�1, and the

(A) (B)

Fig. 17. Comparison of episodic flow models

showing the effects of flow frequency on petro-

leum migration and distribution. Numbers in

parenthesis indicate times needed for accumu-

lating total oil reverse in Inglewood field (see

Fig. 16).

Effects of episodic fluid flow 247

duration of time needed to form the Inglewood oil field

(approximately 450 million barrels) is approximately

34 000–62 000 years depending on the fault permeability

assigned varying 50–5 md. High fault permeability also

allows more petroleum accumulation and channeling in the

Pliocene formation because larger overpressures can propa-

gate further and reach at the upper part of the fault.

In episodic models, the total oil volume in the reservoir

can be accumulated in about 24 000 years under assump-

tions that fault permeability fluctuates between 1–1000 md

and seismically induced flow pulse occurs every 2000 years.

Episodic migration forms larger areas of oil accumulation

with highly petroleum saturation accumulations in a

broader region surrounding the fault zone. Considering

the observed pattern of hydrocarbon accumulation in this

region, the episodic model could be more geologically

meaningful than continuous migration model.

The frequency of episodic flow affects petroleum migra-

tion and distribution patterns in the fault zone. Faster and

broader accumulations appear in the Pliocene sediments if

the pulse period becomes shorter. The frequent episodic

fluid pulse also forms accumulations with higher petroleum

saturation and flow channels in adjacent formations.

ACKNOWLEDGEMENTS

This research was supported by a grant from the U.S.

Department of Energy – Basic Energy Sciences (Grant

number: DE-FG02-96ER14620), The GDL Foundation

also provided a Ph.D. scholarship to the first author, for

which he is extremely grateful.

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Geofluids is abstracted/indexed in Chemical Abstracts

CONTENTS

127 Review of ‘Too Hot To Touch: The Problem of High-Level Nuclear Waste’ by William M. Alley and Rosemarie Alley E.M. Kwicklis

128 Diffusion and kinetic control of weathering layer development D. Reeves and D.H. Rothman

143 Carbon dioxide controlled earthquake distribution pattern in the NW Bohemian swarm earthquake region, western Eger Rift, Czech Republic – gas migration in the crystalline basement F.H. Weinlich

160 Fractal analysis of veins in Permian carbonate rocks in the Lingtanchang anticline, western China B. Deng, S. Liu, L. Jansa, S. Yong and Z. Zhang

174 Fluid effect on hydraulic fracture propagation behavior: a comparison between water and supercritical CO2-like fluid X. Zhou and T.J. Burbey

189 Cementation and the hydromechanical behavior of siliciclastic aquifers and reservoirs D.F. Boutt, K.E. Plourde, J. Cook and L.B. Goodwin

200 Impacts of Pleistocene glacial loading on abnormal pore-water pressure in the eastern Michigan Basin O. Khader and K. Novakowski

221 Numerical simulation of mylonitization and structural controls on fluid flow and mineralization of the Hetai gold deposit, west Guangdong, China J. Zhu, Z. Li, G. Lin, Q. Zeng, Y. Zhou, J. Yi, G. Gong and G. Chen

234 Effects of episodic fluid flow on hydrocarbon migration in the Newport-Inglewood Fault Zone, Southern California B. Jung, G. Garven and J.R. Boles

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