Fractures Faults and Hydrocarbon Entrapment

Marine and Petroleum Geology 17 (2000) 797±814 www.elsevier.com/locate/marpetgeo

Fractures Fractures,, faults, faults, and hydrocarb hydrocarbon on entrapment entrapment,, migration and ¯ow Atilla Aydin* Rock Fracture Project and Shale Smear Project, Department of Geological and Environmental Sciences, Stanford University, Stanford, CA, 94305-2115, USA

Received 27 April 1999; received in revised form 2 April 2000

Abstract This paper present presentss an overvie overview w of the role of struct structura urall hetero heterogen geneit eities ies in hydroca hydrocarbon rbon entrap entrapmen ment, t, migrati migration on and ¯ow. Three common structural heterogeneity heterogeneity types are considered: (1) dilatant dilatant fractures fractures (joints, veins, and dikes); (2) contraction/ contraction/ compaction compaction structures structures (solution (solution seams and compaction compaction bands); and (3) shear fractures (faults). (faults). Each class of structures has a dierent dierent geometry, pattern, pattern, and ¯uid ¯ow property, property, which are described by using analog outcrop studies, conceptual conceptual models, and, in some some cases, cases, actual subsurface subsurface data. Permea Permeabili bility ty of these these struct structures ures may, on averag average, e, be a few orders of magnit magnitude ude higher higher or lower lower than than those those of the correspond corresponding ing matrix rocks. Based on these these dieren dierences ces and the widesprea widespread d occurre occurrence nce of  fractu fractures res and faults faults in rocks, rocks, it is conclud concluded ed that that struct structura urall hetero heterogen geneit eities ies should should be essent essential ial elemen elements ts of hydrocar hydrocarbon bon migrat migration ion and ¯ow as well well as entrapm entrapment ent and that they should be include included d in largelarge-sca scale le basin basin models models and reserv reservoiroir-sca scale le simul simulat ation ion mode models. ls. This This propo proposi siti tion on is suppor supporte ted d by a numbe numberr of case case studi studies es of vario various us rese reserv rvoir oirss prese present nted ed in this this paper. 7 2000 Elsevier Science Ltd. All rights reserved. Keywords: Fractures; Faults; Permeability; Fluid ¯ow; Hydrocarbon seal, migration and ¯ow

1. Introduction

Fractu Fractures res and faults are the most most ubiqui ubiquitou touss and ecient avenue for hydrocarbon migration and ¯ow as well as entrapment. entrapment. Since Nelson's Nelson's (1985) pioneering pioneering book book on fractu fractured red reservo reservoirs, irs, severa severall volume volumess have have been been publis published hed on this this topic topic (Jones (Jones & Presto Preston, n, 198 1987; 7; Ameen Ameen,, 199 1995; 5; Long Long et al., al., 199 1996; 6; Molle Moller-P r-Pede ederso rson n & Koestler, 1997; Jones, Fisher & Knipe, 1998; Coward, Daltaban Daltaban & Johnson, Johnson, 1998; Parnell, Parnell, 1998; Haneberg, Haneberg, Mozley Mozley,, Moore Moore & Goodwi Goodwin, n, 199 1999). 9). Howeve However, r, as the dates of these publications indicate, the importance of  fractu fractures res and faults faults in hydroc hydrocarb arbon on entrap entrapmen ment, t, mimigrat gratio ion n and and ¯ow ¯ow has has just just been been rece recentl ntly y reco recogn gniz ized ed.. Recent advances in borehole and seismic imaging technologies played a crucial role in this recognition. It is

* Tel.: +1-650-725-8708; +1-650-725-8708; fax: +1-650-725-0979. +1-650-725-0979. E-mail address: [email protected] [email protected] nford.edu (A. Aydin).

now impossi impossible ble to take take the previo previousl usly y common common attiattitude that most basins and reservoirs have no fractures or faults. Even though recognition of the existence of fractures and faults in reservoirs is an important forward step, underst understand anding ing the impact impact of these these structu structures res on ¯uid ¯uid ¯ow is far from satisfactory. One reason for the diculty in handling fractures and faults is their complexity; another is the fact that the nature of the fracture/ fault fault contri contribut bution ion to hydroc hydrocarb arbon on entrap entrapmen ment, t, mimigratio gra tion n and ¯ow var varies ies widely widely (Smith (Smith,, 198 1980; 0; Aydin, Aydin, Myers Myers & Younes Younes,, 199 1998; 8; Wa Walsh lsh,, Wa Walte lterso rson, n, Heath Heath & Child, 1998; Knipe, Jones & Fisher, 1998). Each class of structure occurs in a speci®c geological and geomechanical environment and has a speci®c genesis. Each class class has its own own geomet geometry ry (orien (orientat tation ion,, dimens dimension ional al proper propertie ties), s), spacin spacing, g, distri distributi bution, on, connec connectiv tivity ity,, and hydraulic properties, which result in limitations or advantages for hydrocarbon transport and entrapment in

0264-8172/00/$ - see front matter 7 2000 Elsevier Science Ltd. All rights reserved. PII: S0264-8172(00)00020-9

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A. Aydin / Marine and Petroleum Geology 17 (2000) 797±814

a given environment. This paper deals with the classi®cation of structural discontinuities in rocks, their geological, geomechanical, and hydraulic characteristics, and reviews a few selected case studies from both outcrop analog and subsurface cases to demonstrating the impact of fractures and faults on the migration, ¯ow, and entrapment of hydrocarbon.

2. Classi®cation and characterization of fracture/fault systems

The term `fracture' is used in this paper to refer to a structure de®ned by two surfaces or a zone (Fig. 1(a)) across which a displacement discontinuity occurs (Fig. 1(b)). The following classi®cation of such a structure is based on its mode of formation and represents a simpli®cation of a more rigorous geomechanical classi®cation of rock fracturing (Pollard & Aydin, 1988) based on a broader range of possible displacement con®gurations at a fracture's tip line: 1. Dilatant-mode fractures/joints, veins, dikes 2. Contraction/compaction-mode fractures/pressure solution seams and compaction bands 3. Shear-mode fractures/faults

Fig. 1. (a) A fracture and (b) various fracture types classi®ed based on the prominent displacement of the fracture walls as dilatant, contraction/compaction, and shear. (Modi®ed from Pollard and Aydin, 1988).

Structural and hydraulic characteristics of fundamental elements constituting each of these classes will be discussed in the order in which they are listed. 2.1. Dilatant fractures

Dilatant fractures are characterized by a displacement discontinuity that results from fracture walls moving away from, and relative to, each other (see arrows in Fig. 1(b)). This displacement discontinuity is a measure of the mechanical aperture (hm in Fig. 2) and is related to the hydraulic aperture (ha in Fig. 2), which is one of the most important petrophysical parameters characterizing ¯uid ¯ow through a single dilatant fracture. According to the so-called parallel plate model (see, for example, Chapter 3 in Long et al., 1996), the ¯ow rate along a fracture is related to the cube of the aperture; and thus, permeability k j, o f a single fracture in an impermeable medium is given by (Fig. 2): k j

 h  a 

2

a12X

1

Note that here ha is the hydraulic aperture. If the permeability of the matrix rock is signi®cant, then a dual permeability model taking into account the matrix permeability as well as the fracture permeability is appropriate (see Taylor, Pollard & Aydin, 1999, for a table of fracture permeability formulations in terms of a wide range of fracture geometry, shape, and matrix permeability).

Fig. 2. Parallel plate model of a fracture with smooth fracture walls. hm is the mechanical aperture of the idealized fracture. Permeability of such an idealized system driven by an hydraulic head gradient is given by k j ha  2 a12, where ha is the hydraulic aperture. Matrix rock permeability ( kr) is assumed to be negligible.

 

A. Aydin / Marine and Petroleum Geology 17 (2000) 797±814

The fracture permeability de®ned earlier is controlled solely by fracture aperture which is a dynamic parameter most dicult to obtain and to verify from natural fractures. Measured or determined apertures from natural fractures at outcrops (Barton & Hsieh, 1989), in boreholes (Luthi & Souhaite, 1990), in in-situ well tests (Paillet, Hsieh & Cheng, 1987), and tracer tests (Novakowski & Lapcevic, 1994) range from a few hundred micrometers to several millimeters. Among the dilatant fractures, three subgroups, based on genesis, geometry, and contribution to hydrocarbon transport, are considered. 2.1.1. Hydrofractures Hydrofractures form in an environment of high ¯uid pressure (Hubbert & Willis, 1957; Secor, 1968), which is the major driving force for their formation. Hydrofractures may be vertical (dikes) or horizontal (sills) or a combination of the two depending on the interplay between the state of stress and the abnormal ¯uid pressure leading to fracturing (Mandl & Harkness, 1987). Field observations (Verbeek & Grout, 1983) from the Uinta basin in the western United States (for location see the inset in Fig. 3(a)) show that solid hydrocarbon exists in dikes several meters wide and several kilometers long (Figs. 3(a) and 4(a)). The geometry of  some of these hydrocarbon dikes is well known because they have been mined for Gilsonite (Fig. 4(a)), a commercial name for a type of immature hydrocarbon used for various industrial purposes. In the absence of a signi®cant deformation within the solid Gilsonite, it follows that the liquid hydrocarbon ®lled

799

the dikes and that the fractures were conduits for hydrocarbon migration and ¯ow. Those dikes walls exposed by extensive mining show plumose structure (Pollard & Aydin, 1988), typical for dilatant fractures (Fig. 4(b)). In addition, there is evidence that hydrocarbon-®lled fractures exist in the reservoirs within the Uinta basin and that dikes originated from an environment of high ¯uid pressure as demonstrated by pressure distribution data from wells (Fig. 3(b) and (c)). The source of this high pressure in the Uinta basin, however, cannot be unequivocally determined. It has been suggested that a 25- to 30-percent volume increase associated with kerogen/oil transformation was sucient to hydrofracture the Green River shale (Spencer, 1987; Fouch, Nuccio, Anders, Rice, Pitman & Mast, 1994; Bredehoeft et al., 1994), which is the source rock for most hydrocarbons in the Uinta basin. Model studies also show that, once initiated, such hydrofractures are capable of cutting through the impermeable cap rock (Mandl & Harkness, 1987). Evidently, in the Uinta basin hydrofractures cut across not only the source rock and cap rock but also the overlying high-permeability detrital rocks (see the geologic column and map in Fig. 3(a) and (b). It is therefore inferred that the Gilsonite dikes transported hydrocarbons a few kilometers vertically and tens of  kilometers laterally. Given the observed aperture of  the dikes (on the order of several meters, Fig. 4(a)), their lengths and density (Fig. 3(a)), and the expression for permeability derived from the parallel plate model (Eq. (1); Fig. 2), the contribution of this type of permeability fracture to hydrocarbon migration and ¯ow in the vertical and lateral directions is enormous. A

Fig. 3. (a) Geologic map showing a set of northwest-trending Gilsonite dikes in the Uinta Basin, northeastern Utah, and location of the basin (inset) within the state of Utah in western USA. (b) Lithologic column within the basin. (c) Pressure distribution from a well at Altamont ®eld. (a) and (b) are from Verbeek and Grout (1993) and (c) is simpli®ed from Bredehoeft, Wesley and Fouch, 1994.

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similar process has recently been proposed independently for primary hydrocarbon migration and ¯ow in the Austin Chalk, Texas (Berg & Gangi, 1999, which was published during the review process of this manuscript). 2.1.2. Tectonic joint networks Most joint networks in the upper crust form due to crustal and local tectonic driving forces (Pollard & Aydin, 1988). They commonly occur in a set, a large number of subparallel joints in brittle rock units (Fig. 5(a)). Because of the strata-bound nature of these  joints as shown in Fig. 5(a) and (b) (Helgeson & Aydin, 1991; Gross, Fischer, Engelder & Green®eld, 1995), their contribution to vertical hydrocarbon ¯ow from one mechanical unit to another in a multi-lithological medium is rather limited. However, if the joints making up a fracture network have sucient aperture, length, spacing, connectivity, and distribution, they can contribute to the permeability of reservoirs and hydrocarbon production. For example, it has been demonstrated that a set of joints (Fig. 6(a)) observed at surface and detected in a tight sandstone reservoir in the Piceance basin, Colorado, USA (see Fig. 3(a) for location) increases the permeability of detrital reservoir rocks by 10±104 times that of the corresponding matrix permeability (see Fig. 6(b) for permeability table) determined from in situ tests and cores, respectively (Lorenz et al., 1988). It is possible to exploit joint sets if the density and

height of the joints are suciently large by horizontal wells (Fig. 5(b)) and speci®c production technology such as water and CO2 ¯ooding and gravity drainage. The Midale ®eld in Canada (inset, Fig. 6(c)) provides an excellent case for the impact of a fracture set on hydrocarbon production in a carbonate reservoir (Beliveau & Payne, 1991; Beliveau, Payne & Mundry, 1991). A watercut map (Fig. 6(c)) from this reservoir demonstrates the impact of a northwest-trending fracture system on the permeability anisotropy in the ®eld. In this reservoir, a gravity drainage-based recovery method has apparently been successfully utilized. In this eort, aside from the length and spacing of the fractures, the heights of the fractures are also important. Joints frequently occur in clusters or zones which are weaker and, therefore, prone to shearing. Outcrop observations con®rm this conclusion and reveal that a small magnitude of shear is capable of bridging previously separate fractures within a fracture zone thereby increasing not only the aperture of the sheared fracture and the connectivity between neighboring fractures, but also length and height of eective ¯ow pathways (Taylor et al., 1999; Myers & Aydin, 2000). Shearing may also oset thin impermeable shale layers between brittle units with fracture zones, again increasing the connectivity between fracture zones in dierent layers. Field tests and borehole images from shallow aquifers show that ¯uid ¯ow occurs more eectively

Fig. 4. (a) Photograph of one of the dikes mined to several tens of meters depth and several kilometers length. (b) An enlargement of the dike surface showing plumose structure that is evidence for the dilation origin of the original fracture and its southward (towards the viewer) propagation.

A. Aydin / Marine and Petroleum Geology 17 (2000) 797±814

through joint clusters or joint zones (Paillet et al., 1987; Martel & Peterson, 1991; Long et al., 1996). This important concept appears to be applicable also to hydrocarbon reservoirs: The photographs in Fig. 7(a) and (b) illustrate a joint zone with hydrocarbon stain in a limestone core from the Tempa Rossa oil ®eld in the southern Apennines, Italy (Fig. 7(c) and (d)). The photographs show that echelon  joints forming a zone are connected by a throughgoing and zigzagging fracture (Fig. 7(a)) that is probably related to a minute degree of shearing and has the highest degree of hydrocarbon staining (Fig. 7(b)). Some tectonic joint systems are ®lled by vein materials that re¯ect on the role of fractures in focusing ¯uids in the past time. Even though the ®lled fractures are not as eective as un®lled fractures, they may still have higher permeability than the surrounding rocks (Lorenz et al., 1988; Tamanyu, 1999). Contrary to a

801

common misconception about the existence of open fractures at depth, it has been shown that open fractures with large apertures occur as deep as 30 km in the earth (Ague, 1995).

2.1.3. Thermal or desiccation joints Dilatant structures associated with dierential volume decrease due to either cooling or drying occur in certain environments. It is straightforward to identify these joint networks by their orientation (perpendicular to bedding or lava top and bottom) and their commonly polygonal pattern. These joints are important in hydrogeology and waste management (Lore, Aydin & Goodson, 2000a), but they may also contribute to storage and ¯ow of oil and gas in a few rare cases in which the reservoir rock happens to be either volcanic rock or thermally fractured sedimentary rock.

Fig. 5. (a) Photograph showing strata-bound nature of tectonic joint system in the Wingate sandstone overlying apparently unjointed Chinle shale and mudstone, Capitol Reef National Park, Utah, USA. (b) Schematic diagram showing how joints con®ned within isolated brittle units, which can be utilized by an inclined well.

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2.2. Contraction/compaction fractures

Localization of contractional strain within tabular zones is here referred to as contractional or compactional structure. The predominant displacement discontinuity is such that the fracture walls move towards each other (Fig. 1(b)), which may be characterized as anti-crack (Fletcher & Pollard, 1981). This class of  structures includes pressure solution surfaces which usually contain clayey seams that are commonly less permeable in the direction normal to the solution surface (Nelson, 1985; Peacock, Fisher, Willemse &

Aydin, 1998). However, if they are subjected to high ¯uid pressure or shearing in certain environments, they may contribute to in-plane hydrocarbon ¯ow. The impact of these structures on large-scale hydrocarbon migration is not well known, but they may be important in carbonate source rocks and reservoirs. Contraction or compaction bands (Olsson, 1999; Mollema & Antonellini, 1996; Cakir & Aydin, 1994) are another common type of structure in porous rocks and may be characterized by a kinematical con®guration similar to that of the pressure solution structures described earlier. Bands re¯ect a loss of porosity and

Fig. 6. (a) Map showing a joint set in a Mesaverde sandstone outcrop in the Piceance basin. Subsurface data indicate that this NW-trending set also occurs in the reservoir (Lorenz, Warpinski, Branagan & Sattler, 1988). (b) Permeability of major reservoir units measured from core and corrected for stress and water saturation versus those determined by in situ tests from Multiwell experiments. Note that the permeability in the direction of the NW-trending joint system presented in (a) is two to four orders of magnitudes higher than those measured from core. From Lorenz et al., 1988. (c) The impact of fractures on watercut map in the Midale ®eld, a carbonate reservoir in Williston Basin, Canada (see inset for location). Higher permeability direction (NE) determined from this map coincides with the dominant strike of a closely spaced natural fracture system in the reservoir. From Beliveau and Payne (1991).

A. Aydin / Marine and Petroleum Geology 17 (2000) 797±814

have lower permeability than that of the host rock. Therefore, they retard hydrocarbon migration and ¯ow in the direction perpendicular to the bands. The magnitude of this retardation depends on the grain size or pore throat of the band material and their thickness and density of the grains.

803

and (3) the surrounding damage zone (Antonellini & Aydin, 1994; Scholz & Anders, 1994; Caine, Evans & Forster, 1996). Among these, (1) the juxtaposition of  dierent horizons and (2) the occurrence of fault rock distinguish between faults and joints. The three elements of faults and their hydraulics are brie¯y described later.

2.3. Shear fractures/faults

Faults are de®ned as structures across which appreciable shear displacement discontinuities occur. Fault blocks predominantly move along the plane or zone of the discontinuity (Fig. 1(b)). However, displacement discontinuity varies from pure fault plane parallel orientation to pure fault normal orientation which results either in dilation or contraction within the fault zone. Based on the sense of discontinuity, three major types of faults are commonly referred to in geology: strike-slip, normal and reverse, each of which has dierent geometric attributes. Faults have three fundamental elements that impact on hydrocarbon ¯ow: (1) juxtaposition, (2) fault rock,

2.3.1. Juxtaposition of layers across faults Allan diagrams (Allan, 1989) are routinely constructed to visualize juxtaposition geometry across a fault surface in industrial applications. In this process, the most important parameters are fault geometry, slip distribution, and detailed stratigraphy. However, the nature of slip distribution along faults below the resolution of seismic technology and along complex fault zone architectures remain to be problematic in the process of constructing a complete and accurate juxtaposition diagram. Once a juxtaposition geometry with possible highest resolution is constructed, hydrocarbon ¯ow from one permeable unit to another or fault sealing due to juxtaposition of reservoir units against low-

Fig. 7. Photographs showing (a) a fracture zone and (b) hydrocarbon stain on a through-going fracture surface in a limestone core, Tempa Rossa ®eld, southern Apennines, Italy, which is a reservoir controlled by faults and fractures associated with contractional tectonics of the Italian peninsula. (c) is a cross section and (d) is the location map.

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A. Aydin / Marine and Petroleum Geology 17 (2000) 797±814

permeability units may be possible (see, for example, Mathaii & Roberts, 1996; Allan, 1989) provided that the aect of fault rock is negligible or otherwise quanti®able. 2.3.2. Fault rock Fault rock forms the core of a fault and is usually composed of ®ne grain material generated by friction and wear and has lower porosity and permeability than the parent rock. Fault rock may also be made up of shale, salt, or sheared precipitation materials. The author proposed a process based methodology to be used in dealing with fault rock architecture and hydraulics. Here, he presents a few distinct permeability models for fault rock and the surrounding damage zone associated with major faulting processes in common reservoir environments. Deformation bands or shear bands in porous rock form by localization of shearing and volumetric strain along tabular zones. Fig. 8(a) illustrates the permeability structure of an idealized fault zone formed by this mechanism. Although the exact nature of the permeability of such a structure varies based largely upon the nature of the parent rock (Caine et al., 1996; Knipe et al., 1998), it is common to determine about a two to four order of magnitudes reduction in permeability across zones of deformation bands in porous sandstone (Antonellini & Aydin, 1994; Matthai,

Aydin, Pollard & Roberts, 1998; Antonellini, Aydin & Orr, 1999). The plot in the upper part of Fig. 8(a) represents an idealized case of fault-normal permeability, kf  normalized by that of the parent rock (kf ) of closely spaced deformation bands (fault rock) and a damage zone made up less prominent deformation bands (kd). The fault-normal eective permeability of such a block with a thickness, T , having a simple fault rock with a thickness, t, and damage zone with a total thickness, d , is the harmonic average (Eq. 6 in Antonellini & Aydin, 1994): kef 

Â

 k k k T a k k t  k k d  k k T À t À d  f  d r 

d r 

f  r 

f  d

Ã

Thus, the density of deformation band faults in a rock volume of interest and their permeability control the eective permeability of the volume. These parameters are generally related to the lithology of rock and the magnitude of slip across the fault. These faults would seal hydrocarbons depending on the capillary pressure characteristics (Smith, 1980; Weber, Mandl, Pilaar, Lehner & Precious, 1978; Knipe et al., 1998), the quanti®cation of which is an on-going challenge. An outcrop photograph (Fig. 9) from the Arroyo Grande oil ®eld in California, USA (Antonellini et al., 1999) shows tar-impregnated domains in sand and conglomerate bounded by deformation band zones and demonstrates the impact of 

Fig. 8. Idealized fault architectures and corresponding permeability structures. (a) A deformation-band fault zone with reduced permeability ( kf ) in a direction perpendicular to the fault. The degree of permeability reduction depends on the lithology of the rock but on average the reduction is two to four orders of magnitude with respect to that of the rock matrix. (b) A fault developed by shearing across a joint zone. Fault rock formed by this process is similar to that of the deformation band process but it is surrounded by a damage zone, more permeable than the parent rock. (c) A brecciated fault zone ®lled with hydrocarbon. The permeability ( kf ) depends on the porosity of the zone and the ratio of the fault thickness to particle radius.

A. Aydin / Marine and Petroleum Geology 17 (2000) 797±814

this kind of fault on hydrocarbon ¯ow. An analog characterization eort and a subsurface case study at the same locality will be presented later in this paper. The maximum hydrocarbon column height that this type of faults can support is site speci®c and generally depends on the clay content of rock (Knipe et al., 1997). It is also possible to form a fault rock with a similar hydraulic response as the earlier case by a completely dierent faulting process: Shearing along joints (Cruikshank, Zhao & Johnson, 1991; Martel, Pollard & Segall, 1988) or joint zones (Myers & Aydin, 2000). Obviously for smaller osets, fault rock generation is insigni®cant and sheared joint zones are favorable ¯ow pathways as mentioned earlier with reference to slightly sheared joint zones. However, increasing slip generates a fault rock with smaller grain size and porosity (Fig. 8(b)) similar to that of the fault rock formed by the deformation band mechanism. The reduction in permeability normal to the fault rock produced by the two mechanisms is comparable. However, faults formed by shearing along joints or  joint zones are always surrounded by a damage zone made up of joints and slightly sheared joints (Fig. 10). Such a zone and a localized slip surface at the edge of  the fault rock enhance the fault-normal permeability (kd) (as well as fault-parallel permeability) as shown in an idealized plot in Fig. 8(b). Detailed formulation to determine eective block permeability for this case can be found in Jourde, Aydin and Durlofsky (in preparation). There is a large volume of work on the quanti®cation of damage zone geometry and the interpretation

805

of its variation in terms of the process zone associated with the propagation, growth, and widening of the fault width with increasing slip (Walsh & Watterson, 1988; Cowie & Scholz, 1992). In general, the width of  the damage zone and the density of joints therein are related to the magnitude of slip across the fault. Not all dilatant fractures around brittle faults are associated with fault process zones. In some cases the fractures are proved to be older than the nearby faults or are localized in a broad fold associated with a broader deformation ®eld. For example, the hydrocarbon-®lled joints (Fig. 11) in the hanging wall of a thrust fault (Fig. 11(b) and (c)) are observed in outcrops directly above the Orcutt oil ®eld in central California (Lore et al., 2000b). Here the fault represents a component of a high-permeability hydrocarbon pathway that increases the drainage volume by simply connecting the fracture system in the hanging wall. The conceptual models for faults produced by deformation banding (Fig. 8(a)) and slip along joint zones (Fig. 8(b)) may also represent fault rocks composed of  shale or salt (Weber et al., 1978; Smith, 1980; Moore and Vrolijk, 1992; Gibson, 1994; Lehner & Pilaar, 1997). Thus, fault rock associated with faulting in multi-layered brittle/ductile systems also produces a lower permeability fault core similar to the permeability structure in Fig. 8(a) and (b), and plays an important role in hydrocarbon migration and entrapment. The distribution of shaly fault rock is closely related to the process of shale smearing and the fault architecture resulting from such process (Koledoye, Aydin & May, 2000). It turns out that an increasing

Fig. 9. A tar sand domain bounded by a fault in sandstone and conglomerate of the Arroyo Grande oil ®eld, central California. Steam injection breakthrough times show a signi®cant anisotropy which is consistent with the fault orientation and permeability. From Antonellini et al. (1999).

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Fig. 10. Map showing 1 m-wide fault rock at the fault core surrounded on either side by about 2 m damage zone made up of joints and sheared  joints in a sandstone formation in southeastern Nevada. This fault has formed by left-lateral shearing of 14 m across a joint zone whose right stepping con®guration is still discernable. The fault rock is made up of ®ne grained material and has lower permeability than the undeformed rock, whereas the damage zones on both sides have higher permeability due to a network of fractures. From Myers and Aydin (2000). H

Fig. 11. Hydrocarbon ®lled fractures and faults in siliceous mudstone at the Orcutt oil ®eld, Santa Maria Basin (see Fig. 13 for location), central California, USA. (a) Photograph showing hydrocarbon (dark) ®lled joints, (b) cross section showing the joint system, and (c) structural location of (a) and (b) in the hanging wall of a reverse fault also ®lled by hydrocarbon. In this case, the joint system occurs in a broad fault-core anticline. The section in (c) is from Munger, 1986; Dunham Bromley and Rosata (1991). Modi®ed from Lore, Eichhubl and Aydin (2000b).

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deformation may decrease the sealing capacity of such a system. It is also possible that fault zones with smeared shale may be accompanied by a relatively conductive zone as depicted in Fig. 8(b). 2.3.3. Dilation associated with pull-aparts, breccia zones, and slip surfaces Brittle faulting of rock results in volumetric change within the rock body. Dilational volume change takes place either through the entire deformed rock or localizes along discrete structures such as pull-apart openings, slip surfaces, breccia zones, and the associated  joint system already described. These structures are generally conduits for geothermal ¯uids (Aydin & Nur, 1982; Aydin, Schultz & Campagna, 1990; Martel & Peterson, 1991; Forster & Evans, 1991; Bruhn, Parry, Yonkee & Thompson, 1994; Sibson, 1968, 1986, 1994; Ohlmacher & Aydin, 1995), and for hydrocarbon (Reilly, Macdonald, Biegert & Brooks, 1996; Dholakia, Aydin, Pollard & Zoback, 1998; Moretti, 1998). Hydraulic properties of pull-apart openings and slip

surfaces associated with faults are similar to those of  voids and joints. Breccia zones with hydrocarbon (Fig. 12) have been described by Dholakia et al. (1998) and have been proposed to be eective hydrocarbon pathways. Unlike the conceptual models in Fig. 8(a) and (b), the model in Fig. 8(c) is dicult to quantify because of the lack of actual ®eld measurement. Furthermore, the hydrodynamics of this type of fault is dierent from those of a simple parallel plate model (Fig. 2) in the sense that a typical zone includes both breccia of various sizes and shapes and hydrocarbon. However, the permeability (kf ) of such a zone may be approximated as that of parallel plates with cylindrical or spherical asperities as given by Kumar, Zimmerman and Bodvarsson (1991, Eq. 8): K f 

 À p  Á À p  Áà  k 1 À tanh fta2 k a fta2 k b

b

2

b

where kb is a parameter representing permeability of  the breccia without boundaries, f is the porosity, and t is the thickness. Using the Kozeny±Carman model and assuming spherical particles of the same radius `a' within the fault zone would yield: 3 2

2

 f a a451 À f X

kb

3

Substituting Eq. (3) into Eq. (2) gives K f 

3 2

2

Â

Ã

 f a a451 À f  1 À tanhCRaCR  X

4

Here, C  is a function of porosity: C 

À Á  3X4 1ap f À p f ,

R is the ratio of the thickness to the radius of the spherical particles: R

 taaX

Thus, the permeability of such a system depends on the porosity within the fault zone and the ratio of the fault thickness to particle size (or a measure of size distribution for a more general case). 2.3.4. Other parameters crucial for fractures/faults and  hydrocarbon ¯ow

Fig. 12. Photograph showing hydrocarbon-®lled breccia zone within a fault zone in the Monterey Formation at Government Point, coastal central California. Hydrocarbon focusing into faults of various sizes is ubiquitous in both coastal California and the San Joaquin Valley to the east of the San Andreas Fault, which include major oil producing reservoirs in the region. From Dholakia et al., 1998.

2.3.4.1. Slip. The impact of slip on fault permeability is dependent upon speci®c faulting processes. Large slip results in thicker and tighter fault zones in the conceptual model shown in Fig. 8(a). Small slip increases fault-normal and fault-parallel permeability in the model shown in Fig. 8(b). Large slip across the faults that are generated by the same conceptual model decreases fault-normal permeability and increases fault-parallel permeability. For shale smear, large slip increases the distribution of the shaly fault rock along the dip and strike directions of the fault

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and provides a potential for a higher hydrocarbon column. However, at some critical slip value, the continuity of the shaly fault rock may break down, thereby  jeopardizing sealing integrity. The impact of slip magnitude on the permeability provided by faulting related dilational structure is expected to be signi®cant as the size of the opening is proportional to the slip (Aydin & Nur, 1982). 2.3.4.2. Cementation. Open space is prone to become ®lled, if not with hydrocarbon, then with cements and mineral deposits. Once ®lled by cements, these structures are less eective conduits. However, as noted earlier for dilatant fractures, a precipitant-®lled fault zone more often has a higher pore volume (Eichhubl, 1997; Eichhubl & Beal, 1998) and perhaps a higher permeability. 2.3.4.3. Present stress state. High fracture/fault-normal stress reduces aperture, thus inhibiting ¯uid ¯ow, and high fracture-parallel compressive stress increases the ability of fractures/faults to stay open and transport hydrocarbon (Teuful & Lorenz, 1996). High ¯uid pressure is capable of opening fractures/faults at any depth and thus facilitating vertical and lateral ¯ow (Pollard & Aydin, 1988; Engelder & Lacazette, 1990). Shearing, which is promoted by high dierential stress, high ¯uid pressure, or low eective fault-normal stress, focuses ¯uid ¯ow (Aydin et al., 1990; Barton et al., 1995; Zoback & Moos, 1995; Finkbeiner, Barton &

Fig. 13. Location map for major Tertiary basins of the Monterey type along the San Andreas transform boundary, CA, USA.

Zoback, 1997; Dholakia et al., 1998). In fact, shearing is the most eective way to produce dilation at any depth in the Earth's crust. 2.3.4.4. Time. Reservoirs are dynamic systems that evolve through their geological history as well as their production history (Long et al., 1996). Fractures/faults are natural components of this ever-changing system. Earthquake-related ¯uid discharge is a good evidence for the cyclic nature of fault zone hydraulics (Sibson, 1968). The parameters such as time and ¯uid ¯ow distance can also be evaluated for fault-related ancient ¯uid ¯ow (Eichhubl, 1997).

3. Methodology for modeling hydrocarbon migration and ¯ow: a case study

Perhaps one of the best case studies for fault-related hydrocarbon, entrapment, migration, and ¯ow is that of the Monterey-type basins in California (Finkbeiner et al., 1997; Eichhubl, 1997; Dholakia et al., 1998). Therefore, the Monterey basins in California are here used to demonstrate construction of a conceptual model for hydrocarbon entrapment, migration, and ¯ow in a particular environment. Several sedimentary basins of Tertiary age exist along the San Andreas transform boundary throughout California (Pisciotto & Garison, 1981), the largest of which are the Los Angeles, Ventura, Santa Maria, San Joaquin, and Santa Cruz basins (Fig. 13). The socalled Monterey-type basins also occur along the Circum Paci®c margins (Ingle, 1981) and contain huge hydrocarbon and natural gas reserves. These basins represent a unique depositional and diagenetic environment (Graham & Williams, 1985) and have similar rocks composed of diatomaceous and phosphatic shale and minor amounts of chert and dolostone (Fig. 14). The basins are usually ®lled with young detrital conglomerates and sandstones deposits. The basinal rocks can be classi®ed into two major petrophysical groups in terms of their permeability: The Monterey Formation and related rocks have a low matrix permeability (usually under one md, see for example, Johnston & Wachi, 1994), and the turbidite sand pockets and younger detrital units generally have a high matrix permeability (Antonellini et al., 1999). A general model of hydrocarbon maturation, migration, and storage (Fig. 15(a)) depicts a system with a kitchen, conduit bed and a traditional reservoir in the form of an anticlinal structural high (Dickinson, 1976). We here propose a speci®c model for hydrocarbon migration and ¯ow within the Monterey-type basins and other basins with similar petrophysical units and deformation process history. This model, illustrated schematically in Fig. 15(b), is primarily based

A. Aydin / Marine and Petroleum Geology 17 (2000) 797±814

on sound structural principles established by both outcrop analogs and subsurface data from various reservoirs in California. In this model, the organic rich carbonaceous shale is, of course, the source rock (Figs. 13±15). The access pressure associated with transformation of the organic matter into oil and cracking and transpressional tectonic deformation of extremely low permeable Oligocene±upper Miocene rocks are envisioned to produce a series of structures ranging from hydrofractures, or pressurized and brecciated fault zones in orientations parallel and at high angle to bedding (Dholakia et al., 1998). The faulting process was envisioned to be cyclic (Eichhubl, 1997) similar to earthquake-related periodicity proposed for crustal scale faults (Sibson, 1968). Brecciated fault zones and dilatant fractures are major pathways for hydrocarbon migration from the source rock through the low permeability petrophysical units in the stratigraphic column. Interconnected faults and fracture networks de®ne the drainage area and thus producability from a reservoir. The dilatant fractures are either hydrofractures or pressurized fracture zones with a small amount of slippage. As noted earlier, a small magnitude of shear is capable of increasing dimensions of fracture-fault systems and eciency of ¯ow pathways. Brecciated fault zones both at high angle and parallel to bedding are by far the most eective hydrocarbon conduits. Larger slip would normally

809

provide wider breccia zones. Two lines of evidence suggest that the brecciated fault zones in the Monterey basins are propped open by high pressure: (1) several contractional (reverse) faults include tar and breccia zones in which fragments of siliceous rocks are totally disconnected in a hydrocarbon matrix, and (2) bedparallel breccia zones with hydrocarbon are preserved within the zone. The second case indicates that ¯uid pressure within the faults was high enough to lift up the overburden. There are three factors that play important roles in this scenario: low permeability of the rock matrix; petroleum maturation, and diagenesis of the siliceous rocks. The ®rst is a typical characteristic of the siliceous rocks of the Monterey Formation and is required to retain the pressure and hydrocarbon within faults and fracture zones. The second may generate a volume increase within the source, usually organic rich shale, and nearby units in an incremental fashion. The volume change associated with petroleum maturation and cracking was brie¯y discussed earlier. Here it should be noted that the permeability of a fracture (or fault) increases with increasing ¯uid pressure (Walsh, 1981; Engelder & Scholz, 1981). The third is relevant to the formation of layer-parallel anisotropy, and, consequently, to the formation of layer-parallel breccia zones from highly brittle porcelanite (Dholakia et al., 1998), which is the end product of the diagenesis of 

Fig. 14. Geologic columns (from right to left, Santa Maria basin, Salinas basin (Labarere well, Section 21, 23-10), and San Joaquin basins Harvester well, Section 25, 23-21) showing lithostratigraphic and petrophysical units within the Monterey type basins. Lower units are composed of  mostly diatomaceous, siliceous, and phosphatic shales with low permeability, whereas the younger deposits of sand and conglomerate have high permeability. These two petrophysical units demonstrate contrasting styles of faulting and the permeability structure resulting from it. Lithologic data from Dunham et al. (1991) and Graham, Seedorf, Walter and Bloch (1991).

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the siliceous shale (Graham & Williams, 1985; Eichhubl & Beal, 1998). It is interesting to note that the hydraulic properties of faults within the same basin are controlled by the dierent rheology of the rocks in which the faults occur. The low-porosity and low-permeability rocks are deformed by brittle processes that produce permeable fault and fracture zones. In contrast to these dilatant and permeable faults, the faults in high-porosity and high-permeability rocks are contraction faults with lower permeability than that of the matrix rock, and they form barriers to hydrocarbon ¯ow as indicated by outcrop study and core examples from the Arroyo Grande sandstone reservoir in central California (Antonellini et al., 1999). Steam injection breakthrough time from this ®eld demonstrates a nine-toone lateral permeability anisotropy, the largest permeability component being parallel to the strike of the faults and the smallest being perpendicular to the faults. These faults compartmentalize reservoirs, which result in a lack of communication between fault blocks with dierent pressures.

4. Conclusions and discussion

Three major types of structural discontinuities and their geometric and hydraulic characteristics are considered: dilatant, compaction/contraction, and shear. Important dierences exist among the geometry and distribution of these three types. Flow properties also dier from one fundamental type to another and, for a given structure type, from one lithologic and geomechanical environment to another. Joint networks are limited within brittle units but can be eective ¯ow pathways for hydrocarbon production from these units. Horizontal drilling and special production designs such as gravity drainage and various injection methods may help to exploit the fractured reservoirs with joint networks. The most eective elements in a joint network are  joint zones, which are prone to a small magnitude of  shearing. This, in turn, increases the aperture, vertical and lateral connectivity, and produces longer and taller conduits for hydrocarbon ¯ow. Hydrofractures and faults can be conduits that fa-

Fig. 15. (a) A general conceptual model of a hydrocarbon system showing source, kitchen, migration conduit, and reservoir with top seal (From Dickinson, 1976, courtesy of Stephan A. Graham). (b) A structurally based conceptual model for the Monterey type basins showing permeable faults and vertical hydrofractures as conduits in a low permeability petrophysical unit. Breccia zones with hydrocarbon also occur parallel to bedding, which re¯ects the role of high ¯uid pressure in the process of brecciation and hydrocarbon invasion of the breccia zone. In top portion of  the basin, the petrophysical unit is of high permeability, but the faults are of low permeability, thereby behaving as barriers for hydrocarbon ¯ow. Faults of this type provide lateral seal for hydrocarbons and compartmentalize reservoirs.

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cilitate primary hydrocarbon migration. High ¯uid pressure, which is a prominent characteristic of hydrocarbon source rocks, and shearing are capable of producing open fractures and dilatant faults at all depths of interest to hydrocarbon exploration and production. Faults have complex architectures that may enhance and/or impede hydrocarbon migration and ¯ow depending on the speci®c process of faulting and its impact on the characteristics of the three fundamental elements of the fault zone architecture: juxtaposition, localized dilation, and fault rock. Other parameters, such as slip magnitudes, cementation, stress state, and time, are also crucial for evaluating the eciency of  fault ¯ow and fault seal systems. A cursory survey suggests that, at least, four categories of fault behaviors exist. These are: 1. transmitting faults, 2. sealing faults, 3. vertically transmitting and laterally sealing faults, and 4. faults sealing or transmitting intermittently. These are rather end-members. A systematic study of the permeability structure of faults and fractures in various geomechanical and depositional environments is required for constructing conceptual models, which in turn can be tested in the ®eld as well as in simulation models. The methodology for doing this is now established. It is now possible to conceptualize the separate pieces of information about fractures and faults and their hydraulic properties and to construct a model for hydrocarbon migration, ¯ow and entrapment within a particular environment. In this respect, the example from the Monterey type basins in California is encouraging and is in striking contrast with sedimentologic models for hydrocarbon migration and engineering models of fracture/fault networks commonly used in reservoir simulation (see for example, Warren & Root, 1963). Hydrocarbon migration within a basin is largely a physical phenomenon and fractures and faults are dominant components of it. Basin models without this physical perspective and its dominant elements are bound to be incomplete.

Acknowledgements

Research leading to this presentation has bene®tted from many of my colleagues and former and present graduate students, a partial list of which includes Marco Antonellini, Charlie Brankman, David Campagna, James DeGra, Sneha Dholakia, Yijun Du, Peter Eichhubl, Radu Girbacea, Daniel Helgeson, Judson Jacobs, Simon Kattenhorn, Bashir Koledoye, Jason Lore, Stephan Matthai, Pauline Mollema, Rodrick Myers, Gregory Ohlmacher, David Pollard,

811

Thomas Roznovsky, Richard Schultz, Lans Taylor, Amgad Younes, and Manuel Willemse. I thank Stephan Graham, Fikri Kuchuk, Herve Jourde, and Robert Zimmerman for their help in various stages of  this manuscript. Financial support from the Rock Fracture Project (Agip, Anadarko, Aramco, Arco, BPAmoco, Chevron, Conoco, Elf, JNOC, Marathon, Mobil, Norsk Hydro, Phillips, Repsol/YPF/Maxus, Shell, Texaco, Total/Fina, and Western Atlas/Baker Hughes) and Shale Smear Project (Chevron, Conoco, Elf, JNOC, and Marathon) at Stanford University, and from the US Department of Energy, Basic Energy Sciences, Grant No. DE-FG03-94ER14462 is also acknowledged. I thank Victoria Doyle-Jones for her editorial help.

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