Fault Characterization by Seismic Attributes and Geomechanics in a Thamama Oil Field, United Arab Emirates

GeoArabia, Vol. 9, No. 2, 2004 Gulf PetroLink, Bahrain Fault characterization, Thamama oil field, UAE

Fault characterization by seismic attributes and geomechanics in a Thamama oil field, United Arab Emirates

Yoshihiko Tamura, Futoshi Tsuneyama, Hitoshi Okamura and Keiichi Furuya

ABSTRACT

Faults and fractures were interpreted using attributes that were extracted from a 3-D seismic data set recorded over a Lower Cretaceous Thamama oil field in offshore Abu Dhabi, United Arab Emirates. The Thamama reservoir has good matrix porosity (frequently exceeding 20%), but poor permeability (averaging 15 mD). Because of the low permeability, faults and fractures play an important role in fluid movement in the reservoir. The combination of the similarity and dip attributes gave clear images of small-displacement fault geometry, and the orientation of subseismic faults and fractures. The study better defined faults and fractures and improved geomechanical interpretations, thus reducing the uncertainty in the preferred fluid-flow direction. Two fault systems were recognized: (1) the main NW-trending fault system with mapped fault-length often exceeding 5 km; and (2) a secondary NNE-trending system with shorter faults. The secondary system is parallel to the long axis of the elliptical domal structure of the field. Some of the main faults appear to be composed of en- echelon segments with displacement transfer between the overlapping normal faults (relay faults with relay ramps). The fault systems recognized from the seismic attributes were correlated with well data and core observations. About 13 percent of the fractures seen in cores are non-mineralized. The development of the fault systems was studied by means of clay modeling, computer simulation, and a regional tectonics review. The existing fluid-flow characteristics of individual faults and fractures in the field can be modeled using the present-day stress regime, with the maximum horizontal stress oriented north-northeast. Slip-tendency and dilation-tendency analyses simulating present-day regional stress conditions are indicators of fault and fracture transmissibility. The NNE-striking secondary fault system is parallel to the present- day maximum horizontal stress and could act as a flow conduit in the reservoir.

INTRODUCTION

Present-day stress regimes acting on fault and fracture systems can control where fluid flows within hydrocarbon reservoirs (e.g. Heffer and Dowokpor, 1990). The objective of this study is to accurately map the fault and fracture systems that affect fluid flow in the Thamama reservoir of an offshore United Arab Emirates oil field (Figure 1). Fault and fracture systems occur at many spatial scales, and are grouped here into: (1) seismic scale, (2) subseismic scale, and (3) micro scale.

Seismic-scale faults are routinely imaged with 2-D and 3-D seismic data. Recent improvements, particularly in 3-D seismic acquisition and advanced processing techniques, provide clear images of subtle structural features and facies distribution in hydrocarbon reservoirs. By utilizing a variety of attributes extracted from 3-D seismic data (e.g. dip, similarity, curvature), the subsurface can be further analyzed to estimate the geometry of small-displacement faults (Figure 2).

Subseismic-scale fault and fracture systems, however, are not possible to image using compressional waves alone. These more subtle systems may be indirectly modeled by using outcrop analogs, and physical experiments of both clay and sand materials. These analog models are then calibrated to the actual reservoir by using sensitivity analysis of the experimental settings through numerical simulation. This study used an analog-modeling apparatus consisting of two arms to apply regional stress, and a balloon for dome growth in the central part. These experiments were done at Southwest Research Institute in San Antonio, Texas, USA (D.A. Ferrill, D.W. Sims, A.P. Morris and D.J. Waiting, unpublished JNOC Report 2001).

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Maydan Fateh 52°E54Salman ° Hamidiyah 56° Mahzam Bul Falah Fateh SW Hanine (Sassan) North Dome Sajaa Idd Al-Shargi Nasr Rashid Moveyeid Studied Field Juwaiza South Dome Kahaif Abu Al Bu Danah Dubai Mandous A-Structure North Bukhoosh Khubai Umm 25° Al-Karkara El Shaif Margham Bunduq Belbazem Arabian Gulf QATAR A-Structure South Bu Haseer Umm Umm Al Dholou 25°N Satah Al Salsal Bin Nashef Zakum Jarnain Umm Arzanah Saath Khusub Al Razbooth Mubarraz Al Dalkh Bu Jufair Umm C Abu Dalma Dhabi Al Anbar UNITED ARAB A EMIRATES Ghasha Zal Hair B Umm Al Lulu Dalmah Neewat Al Ghalan Hail Jarn Yaphour

Shanayel Shuweihat Al Dabb'iya Rumaitha N Arjan 050 Ruwais Bida Al Qemzan Murban-Bab OMAN km Sahil

Shams TURKEY Caspian SAUDI Sea Bu Hasa ARABIA SYRIA Asab Riqeah NDhafra Safah Med Sea IRAN 0 300 Marzuk Huwaila Haliba IRAQ km JORDAN Mushash KUWAIT 23° Arabian L-II-B Bu Qalla L1 G Lekhwair Madiq Gulf Al Barakah BAHRAIN Shah ° QATAR 2 23 Lekhwair E2 Daleel EGYPT Arabian Zarrarah Qusahwira Mender UAE Shield 1 OMAN 3 Mezoon Dhulaima 52°SAUDI ARABIA 54° Shaybah Red SUDAN Sea

YEMEN Figure 1: Location map of the studied field in offshore United Arab ERITREA Arabian Sea Emirates.

ETHIOPIA Gulf of Aden

Micro-scale fractures are usually analyzed using WORK FLOW cores and Borehole Image Logs. In our study they were analyzed mainly from core samples (vertical Fault Geometry Interpretation and deviated wells), since the image quality of 1) Seismic attribute interpretation acquired Borehole Image logs did not allow for - For seismic-scale faults; conventional approach utilizing seismic attributes (dip, similarity, curvature) their detailed analysis. 2) Analog study - For subseismic-scale faults; modeling experiments, GEOLOGICAL SETTING numerical simulation and outcrop observations

The oil producing Thamama Group (Figure 3) in the studied oil field consists of multiple layers of Integrated Geological Model chalky carbonate reservoirs with uniformly poor core permeability, averaging 15 mD, associated with relatively high porosity, frequently above Fault Flow Characterization 20 percent. The net-to-gross thickness is estimated 3) Geomechanics interpretation to be approximately 300/600 ft. The matrix - Slip tendency and dilation tendency properties of these reservoirs can be enhanced by 4) Well data interpretation - Fracture observation on core and borehole images a fluid conductive fault/fracture network, and by - Multi well interference tests fracture corridors. The domal structure of the field is likely to be related to a deep-seated salt diapir Figure 2: Work flow summary illustrating the of infra-Cambrian Hormuz Salt (Figure 4). integration of seismic mapped faults with the Previous studies provided evidence that wrench clay/sandbox analog modeling experiments and tectonics played an important role in the structural geomechanical interpretations. evolution in the region (Marzouk and El Sattar,

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UNITED ARAB EMIRATES HYDROCARBON HABITAT AND STRATIGRAPHY

Seq. Central and Strati- Western Northeast Southeast Shows graphy (Sharland System Group et al., 2001)

Limestone Simsima

Fiqa Oolitic grainstone Upper

Aruma Halul

Cretaceous Laffan Dolomite Ruwaidha Tuwayil Mishrif Gypsum, anhydrite Shilaif Mishrif AP8

Sandstone Wasia Middle Mauddud Cretaceous Nahr Umr Shale

Shu'aiba Bab Member Source rock Kharaib Aquifer Lekhwair Lower Lower

Gas Thamama Cretaceous Habshan MFS J110 Manifa Oil Asab Hith Oolite 149 Ma Minor oil Arab ABC Arab-D (Lower) Arab-D Upper Hanifa MFS J70 Diyab Upper Jurassic Tuwaiq Mountain Lst. Hadriya Upper Araej

Sila AP7 Lower Araej Uwainat Figure 3: Jurassic Izhara and Cretaceous stratigraphy of

Jurassic Hamlah the United Arab Lower/Middle Marrat Emirates.

1995, Figure 4). At least two distinct tectonic events with different compressive stress directions are interpreted from the features of the Arabian Plate. One is the EW-directed ‘Oman stress’ associated with the Oman Mountain nappes and ophiolite obduction during the Mesozoic. The other is the NNE-directed Cenozoic ‘Zagros stress’. These different stress events reactivated pre-existing basement fault networks, and triggered salt swelling of the infra-Cambrian salt. The salt activation resulted in the structural growth of anticlines above the salt pillows and salt domes in the region. Rapid structural growth at the end of the Middle Cretaceous under the ‘Oman stress’ regime is one of the key factors for the structural doming and faulting of the studied field.

FAULT GEOMETRY INTERPRETATION

In order to investigate seismic-scale fault geometry, the following seismic attributes were extracted from single 3-D seismic data. (1) Time Dip; (2) Azimuth; (3) Edge Enhancement; (4) Instantaneous Phase; and (5) Curvature (Figure 5, Curvature not illustrated). In this particular oil field, the Time Dip-processed image gives the best visual fault enhancement. The faults were mapped using time slices in each attribute cube every 4 or 8 milliseconds. Lineations observed on time slices were interpreted as seismic-scale faults after being confirmed by other attributes and by vertical seismic cross-sections.

Figure 6 shows an example of fault interpretation on a Time Dip attribute image. Two fault systems are present in this field. The main NW-trending normal faults are commonly traceable for more than 5 km across the structure. They are visible as approximately parallel lineations spaced about 1 km apart in the crest, and as arcuate traces on the flanks of the structure. The secondary NNE-trending normal faults are shorter and less common. The secondary fault system occurs along the long axis of the structure as relatively short fault segments.

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Bitlis Suture 50°E 60° Caspian Faults Sea Faults undefined Normal faults Thrust/reverse faults EURASIAN PLATE Colour Code Zagros Suture Cenozoic - active Mediterranean Cenozoic - inactive Sea Mesozoic and Zagros Mountains Cenozoic Volcanics Mesozoic & Cenozoic Mesozoic Palaeo-, Meso- & Cenozoic Palaeozoic ° 30° 30 N Infra Cambrian and Levant Fault Infra Cambrian older (cratonized) ARABIAN Salt Basin PLATE

Basement Studied O Field m a n M ts .

20° 20° AFRICAN Red Sea PLATE Rift

N Indian 0 500 Ocean

km 40° Gulf of Aden Rift50° 60°

Figure 4: Schematic structural geological setting of the Arabian Peninsula with major tectonic elements. Map courtesy of GeoTech, MEGMaps-2 project.

NW-Trending Normal Faults (Main Faults)

Figure 7 shows a vertical seismic section with fault traces based on the interpretation of time slices in the attribute cube. Most of the faults are high-angle normal faults belonging to the main NW-trending normal fault system. The maximum fault displacement along the target horizon is just over 140 ft, and the average is less than 30 ft. Horst-and-graben blocks occur in the central part of the structure. Changes in the dip angle of the fault planes are observed in an argillaceous limestone unit that is mechanically more ductile than surrounding beds. This phenomenon can also be seen in outcrops with ductile, typically shale, intervals. Therefore, it might be possible to make lithological predictions from a detailed analysis of the fault geometry. In addition to the normal faults discussed above, a younger fault system that might be related to the Zagros stress is present above the target interval.

A detailed interpretation of the fault geometry was made using the 3-D seismic attributes (Figure 8). The minimum curvature plot along the target horizon provides a detailed image of fault geometries in the field (Figure 8a). Subseismic-scale faults or fracture swarms might be indicated by small curvature anomalies. Close-ups of the main NW-trending normal faults show that what appeared to be one large fault in the overview (Figure 6) is actually a series of smaller en-echelon faults. The overlapping segmented geometry of these faults is indicative of relay faults and the associated relay ramps. Usually relay ramps are bound by a set of faults striking parallel and dipping in the same direction (Figure 8d). Some of the relay ramps are bound by normal faults with opposing dips, creating horst-like structures between the bounding faults (Figure 8c). These are common features in normal-fault systems at all

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(a) Structural Time Dip (b) Azimuth

05km 05km

Figure 5: Examples of four 3-D seismic attributes are shown as time slices over the studied field.

scales, when the faults are arranged en-echelon. In the overlap zone of the en-echelon faults, displacement transfer takes place between the faults. This causes a dip change of strata in the displacement transfer zone that is called a relay ramp (Figure 8c and 8d). Relay ramps are bedding- dip anomalies bounded at each end by cut-off.

Two types of fault propagation can be seen: these are the classical ‘parallel’ type and a curved ‘lateral propagation’ type. A high degree of fracturing that is not necessarily parallel to the main fault trend can be expected in the displacement transfer zone in both types of relay fault geometries.

NNE-trending Normal Faults (Secondary Faults)

The secondary NNE-trending faults are aligned parallel to the long axis of the structure and intersect the main faults approximately at right angles (Figure 6). There is no uniform geometrical intersection relationship between the two fault systems. Some of the secondary faults appear to cut across the main fault trend without relative displacement, whereas other secondary faults appear to abut against the main trend (Figure 6). This secondary fault system corresponds to a similar fault system (at least in the case of its trend) that was seen in the physical analog modeling experiments with clay material (see below).

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Horst N Secondary faults

Graben Main faults

Horst

05km

Figure 6: Time Dip image (a) with fault interpretation, dipping south and west in red, and north and east in green (b). Note the two almost perpendicular fault systems. Main fault system in red, secondary fault system in blue. Down-thrown block indicated by rectangle symbols.

FAULT DIP ANGLE CHANGE ON SEISMIC CROSS-SECTION South North

Horst Graben

Changing fault dip

Figure 7:950 Changes 1,000 in the 1,050 dip angle 1,100 of the 1,150 fault 1,200planes are 1,250 observed 1,300 and 1,350 attributed 1,400 to argillaceous 1,450 units, which behave mechanically more ductile than the overlying and underlying carbonate strata.

APPLICATION OF PHYSICAL ANALOG MODELING EXPERIMENTS

Clay and sandbox analog modeling experiments were conducted to simulate the interpreted fault systems of the 3-D seismic data. Model simulation included circular and elliptical domes with extension, contractional and strike-slip regional deformation settings. Oblique extension with simultaneous domal uplift was found to yield the best visual analogs with the field data (Figure 9).

Visual comparison between the seismic data (Time Dip image) of the field and the clay experiment shows similarity between both data sets. Fault features such as branching faults, en-echelon normal faults with relay ramps, and laterally curved-fault propagation linked by displacement transfer zones can be seen. Prediction of subseismic-scale fault and fracture geometries is possible based on the analogy of physical model experiments.

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Interpretation

The main NW-trending fault system appears to be related to the regional dextral strike-slip deformation, as similar trending faults were observed in nearby fields. The cause of the deformation is the approximate EW-directed ‘Oman stress’ associated with the Oman Mountain nappes and ophiolite obduction during the Late Cretaceous. Salt swelling occurred concurrently with this dextral strike- slip setting. The secondary NNE-trending normal faults and fractures are believed to have propagated along the long axis of the structure, which is perpendicular to the direction of greatest extension during swelling of an elliptical dome. The subsequent exposure of the structure to the ‘Zagros stress’ might have further enhanced this trend or caused propagation of existing fractures and faults.

Fault Statistics

Statistical fault analyses provided insights into the smaller-scale fault geometry of the main fault system. Fault heave and throw were calculated every 250 m along the seismically mapped main faults of the target horizon of the field. Figure 10a is a fault-heave plot along the strike of a typical main fault showing multiple displacement maxima. This indicates the composite nature of the faults, which is possibly related to the joining-up of several, initially en-echelon, smaller faults.

This interpretation is statistically supported by the particularly small fault heave-to-length ratio observed from the seismic data in comparison to outcrop observations (Figure 10b). Typical heave-to- length ratios calculated from seismic data are less than 0.003, which is considerably smaller than the heave-to-length ratios of 0.1 to 0.01 observed in outcrop in West Texas. That indicates that faults in the oil field are very long, but have little displacement when compared with outcrop observations.

To further investigate the composite nature of the faults, the heave-to-length ratio of individual fault segments was analyzed. Fault segments were selected based on the fault-heave plot of individual faults (Figure 10a). Most of the heave-to-length ratios for individual fault segments were again found to be less than 0.01 (Figure 10b), which means that faults in the studied field still have an extreme heave-to-length ratio in comparison with outcrop observations considering the composite nature of faults from seismic data. One likely reason is the limitation of seismic data resolution; that is, the high heave-to-length fault segments might in turn be composed of smaller fault segments that cannot be resolved from the seismic. Another possibility is a strike-slip component that would increase the apparent fault length. Although the seismic data does not show any evidence of strike-slip fault movement in this field, the regional geological setting and core observations could imply some strike- slip movement along the main faults.

EFFECT OF FAULTS AND FRACTURES ON FLUID FLOW

Present-day stress influences the flow in matrix reservoirs as well as in fractured reservoirs (Heffer and Dowokpor, 1990; Heffer et al., 1992), and it can also significantly influence the fluid flow along faults and fractures (Barton et al., 1995). Non-mineralized faults and fractures, trending parallel to the maximum principal stress, generally have a higher aperture than those trending perpendicular to the maximum principal stress (Carlsson and Olsson, 1978).

Borehole breakout analyses indicated that the maximum horizontal present-day stress orientation is NNE-SSW in this oil field. It is deduced from core measurements that the maximum horizontal stress also corresponds to the maximum principal stress, with the intermediate principal stress being vertical. Therefore, at present, the oil field is in a strike-slip stress regime.

Geomechanical Interpretation

Slip tendency (Ts) and Dilation tendency (Td) can be used in a semi-quantitative characterization of the fluid-flow behavior of non-mineralized faults and fractures striking in various directions within a given stress field (Morris et al., 1996).

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RELAY FAULT SYSTEMS Two faults merged by curved propagation

2 1 Relay ramp with parallel faults 2

TWO RELAY RAMP TYPES

Relay ramp with azimuthally Relay ramp with opposing fault dip parallel fault planes

A B

Horst A’

B’

Cross section A-A’ Cross section B-B’

Horst

Ultimate hanging wall

Fault plane Ultimate footwall Fault plane Relay ramp Relay ramp

Figure 8: (a) Minimum curvature image showing two types of relay fault features: curved fault propagation and relay ramp. (b) Two types of relay ramps can be distinguished on the seismic dip images. The relay ramp can be bounded by azimuthally opposing fault dip, thereby forming either a small horst or graben (c), or parallel dipping faults (d).

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CLAY MODELING

Movable w

rubber sheet all attached to ~ 39 cm Figure 9: (a) Mechanically brittle stratum was simulated by a 2.5 cm thick clay layer resting Inflatable on a rubber sheet. The clay is composed by bladder under rubber sheet weight percent of kaolin (27.7%), custer to simulate feldspar (16.6%), flint-200 mesh (11.1%), and domal uplift water (44.6%). A rubber sheet was attached to the mobile walls, and displacement of the Rubber sheet with walls controlled regional extension and/or 2.5 cm thick clay layer shortening. An inflatable bladder was placed below the rubber sheet to simulate doming.

b) Extension prior to start of doming c) Doming prior to start of extension

0 cm 2 0 cm 2

Main fault Graben Secondary fault

Relay ramp

(b) Extension prior to the onset of doming (c) To simulate the graben structures and simulates the geometry and relative abundance sinusoidal faults observed on the seismic data, of the perpendicularly-oriented main and we investigated the best timing of initiation of secondary fault system. Three centimeter of faulting by regional extension and doming. extension was applied before the initiation of Eventually dome uplift was started two minutes doming. Total extension was 5.5 cm and prior to the onset of ‘regional’ extension to maximum uplift was 0.8 cm at the crest of the synchronize one set of faulting by regional dome. Extension velocity was 6 cm/hour and extension and doming. Then the dome uplift uplift velocity was 2 cm/hour. was halted at 1.7 cm and ‘regional’ extension was continued until ‘stretching’ reached 6 cm.

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(a) Fault Heave Plot (b) Fault Heave vs. Length Plot 35 segment heave y = 0.1x fault segments 30 y = 0.05x

2 km 25 Fault Heave y = 0.01x 20

Segment length 15 Figure 10: (a) The fault heave (horizontal Segment Heave (feet) y = 0.007x displacement) is highly variable along the strike of 10 the faults mapped in the investigated oil field. The heave distribution along the fault traces indicates 5 that each fault actually consists of several short segments merged into one large fault. (b) The 0 merged nature of fault segments is further supported 0 500 1,000 1,500 2,000 by the relatively low heave-to-length fault ratios of Segment Length (feet) less than 0.003 calculated for these faults from seismic. This indicates that faults in the oil field are very long, but have little displacement when compared, for example, with outcrop observations from west Texas, which are illustrated here. The heave-to-length ratios of 0.1 to 0.01 are typically observed in these outcrops.

τ σ σ σ σ σ Ts = / n Td = ( 1- n)/( 1- 3) Where: σn = normal stress, τ = shear stress, σ = maximum principal compressive stress, and σ 1 3 = minimum principal stress.

Slip tendency is defined as the ratio of shear stress to normal stress on the fault or fracture surface. It depends on the stress field, orientation of the surface and frictional characteristic controlled by rock physical properties. Slip tendency analysis is a way of deciding which faults in an oil field are most likely to have slipped or have current slip potential. Such faults or fault segments could be associated with zones of enhanced fracture permeability. The present-day stress orientation and magnitude (in addition to fluid pressure within the reservoir) control the dilation of faults and fractures, and therefore the tendency for faults to be conductive to flow.

With this method, it was possible to rank the seismically-mapped faults and fault zones in the oil field according to their potential fluid transmissibility. The results indicate strong anisotropic fault transmissibility (Figure 11). Magnitudes of slip and dilation tendency for faults belonging to the secondary fault system are 2 to 10 times higher than those grouped in the main fault system. Assuming that both fault systems are non-mineralized, the results of slip tendency and dilation tendency imply that individual NNE-trending secondary faults have a higher transmissibility than the dominant, primary NW-trending fault system. Further assuming that these NNE-trending faults create discrete fracture corridors with interconnected fracture and fault networks, these results indicated that preferred fluid flow in the direction of the secondary fault systems might exist within this oil reservoir. Circumstantial evidence from interference tests corroborate that such a flow anisotropy exists in this reservoir.

Well Data Indicating Anisotropic Transmissibility

An anisotropic transmissibility of the faults and fractures in this oil field can also be inferred from the fracture interpretation of core samples and from the results of a multi-well interference test. The rose diagram in Figure 12a shows all fracture strikes observed in core samples over the field. NW-trending strike directions are dominant, which is consistent with the main fault trend. There are fewer fractures in the secondary fault direction. Over the sampled interval, 520 fractures were observed of which about 13 percent (65 fractures) were non-mineralized. The rose diagram of non-mineralized (open) fractures observed in core samples is shown in Figure 12b. There are two distinct non-mineralized

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(a) Slip Tendency of Fault (b) Dilation Tendency of Fault

N N

05km 05km

High Slipping/Dilatant High N N fault Maximum horizontal stress

W E W E Slip Tendency Slip Dilation Tendency Dilation

Compressive S Low fault S Low Figure 11: (a) Slip-tendency map of faults mapped from seismic. A high slip tendency is modeled in the secondary NNE-trending faults (reddish colors), whereas lower slip tendencies are expected in the main NW-trending fault system (greenish colors). This modeling result is not surprising, since the main fault trend is approximately perpendicular and the secondary faults are almost parallel to the maximum horizontal in-situ stress. (b) Dilation tendency map of faults mapped from seismic. A high dilation tendency is modeled in the NNE-trending faults and a low dilation tendency is predicted for the main NW-trending faults. Dilation and slip tendency indicates that, in the theoretical case of both fault trends being non-mineralized, individual NNE-trending faults are more likely to be fluid conductive.

fracture trends. One is NNE, which parallels the secondary fault strike, and other non-mineralized fractures are parallel to the NW main fault trend.

For the following reasons, a preferential flow through and along the NNE -trending faults and fractures is suggested:

1) The NNE-trending fractures are aligned with the present-day maximum horizontal stress, and therefore have higher dilation and slip tendency than the NW-trending fractures under in-situ stress condition. 2) More than 90 percent of the NW-trending fractures are mineralized, whereas almost all fractures trending NNE are non-mineralized.

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FRACTURE STRIKE "OPEN" FRACTURE STRIKE (520 samples from Cores) (65 samples from Cores) (b) (a) N N 30° 8 30° 30° 10 30°

6 8

60° 60° 60° 6 60° 4 4 2

W E W E -8 -6 -448 6 -10 -8 -6 -4 -2 6 8 10 -2

-4 30° 60° 30° 60° -6 -6 -8 60° 30° 60° 30° -8 -10 S S Figure 12: Composite rose diagrams of natural fracture strike measured from oriented core samples. (a) Both mineralized and non-mineralized fractures. (b) Non-mineralized fractures only.

3) The NW-trending fractures are thought to be older than the NNE-trending fractures. The NW-trending fractures are most likely created during the Oman Mountain deformation in the Late Cretaceous. The majority of the NNE-trending non-mineralized fractures are believed to be related to, or were reactivated during, the Tertiary Zagros collision. In addition these faults and fractures could have been re-activated during the continuous growth of the domal structure. These faults and fractures will therefore probably crosscut the older NW-trending system. Some of the older NW fractures/faults might also have been reactivated during this time as documented by the rare non-mineralized fracture in this direction. 4) Some of the NW-trending open fractures observed on cores, might actually be closed when under the influence of the maximum principal compressive stress perpendicular to the fracture strike, and may therefore be non-fluid conductive under downhole reservoir stress conditions.

In the target field, multi-well interference tests in wells spaced on average about 2 km were conducted. These showed a strong anisotropic transmissibility with a maximum in a northeasterly direction and a minimum towards the northwest. Assuming an interconnected network of non-mineralized fractures with a fracture network permeability exceeding the matrix permeability, this result is consistent with the theoretical results predicted from the geomechanical modeling.

CONCLUSIONS

In this study, two distinct fault systems are described in detail utilizing 3-D seismic attributes. Most of the faults are NW-trending normal faults. They are fairly long and constitute the main fault system, which is associated with predominantly mineralized fractures in cores. This fault/fracture system is interpreted to have originated during the Late Cretaceous Oman Mountain deformation. A secondary fault system, with much shorter faults, trends NNE. It is characterized by mostly non-mineralized fractures. The NNE-trending fault and fracture system parallels the long axis of the elliptical domal structure of the field, and is probably related to the growth of this domal structure and the Tertiary Zagros stress.

The best seismic attributes for fault interpretation are Time Dip, Similarity and Curvatures, which give clear images of small displacement fault geometries. Even though the number of seismic-scale secondary faults is limited, geomechanical modeling indicates that preferred fluid flow is expected through the faults and fractures belonging to this secondary fault system under the present-day NNE-trending maximum horizontal stress and reservoir conditions. The faults are normal faults composed of small fault segments with relay faults and displacement transfer zones. Physical analogs modeling experiments with clay materials and outcrop observations provide us with detailed fault geometry and imply the occurrence of subseismic-scaled faults and fractures.

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ACKNOWLEDGEMENTS

This paper resulted from work at the Technology Research Center of Japan National Oil Corporation (JNOC/TRC). We thank Abu Dhabi National Oil Company (ADNOC) for permission to publish this paper. We also acknowledge the contributions from the Southwest Research Institute (SWRI) scientists, especially Darrell Sims, David A. Ferrill, Alan P. Morris and Deborah J. Waiting, who carried out physical analog modeling experiments and fieldwork in West Texas. Editing, and the drafting of the final figures were by Gulf PetroLink.

REFERENCES

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ABOUT THE AUTHORS

Yoshihiko Tamura is a Senior Geologist with Japan Oil Development Co., Ltd.(JODCO) in Tokyo. He received a BSc in Mineralogy, Petrology and Economic Geology from Tohoku University, Japan in 1985. Prior to becoming a member of the Joint Study Team comprised of Japan National Oil Corporation (JNOC, Currently JOGMEC) and JODCO since 2000, Yoshihiko worked for Sakhalin Oil and Gas Development Company (SODECO) as a Senior Geologist from 1997, and for Japan China Oil Development Company (JCODC) from 1985 to 1993. He is a member of the Japanese Association for Petroleum. [email protected]

Futoshi Tsuneyama is working on his PhD in Geophysics at Stanford University. Futoshi was a Senior Geophysicist with Japan National Oil Corporation (JNOC) until June 2002. He joined JNOC in 1999 and was a member of the Joint Study Team for the Middle East area. He received a MSc in Geology and Mineralogy from Niigata University, Japan in 1989. Between 1989 and 1998, he worked for Idemitsu Kosan in the upstream division. Futoshi is a member of the EAGE, SEG, SEG Japan and Japanese Association for Petroleum Technology. [email protected]

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Hitoshi Okamura is a Deputy General Manager of Geophysical Department INPEX CORPORATION. He was a Research Project Manager with Japan National Oil Corporation (JNOC, currently JOGMEC). He received a ME in Geology and Mining from Akita University, Japan. Hitoshi joined JNOC in 1984 and has been responsible for the carbonate reservoir characterization project for the Middle East since 1999. Between 1995 and 1998, he worked for Abu Dhabi Marine Operating Company (ADMA- OPCO) as a Review Geophysicist. Hitoshi is a member of the Japanese Association for Petroleum Technology and SEG Japan. [email protected]

Keiichi Furuya is a Geophysicist with Japan Oil Development Co., Ltd. (JODCO) in Tokyo. He has a BSc (1993) and a MSc (1995) in Earth Science from Chiba University, Japan. Keiichi joined JODCO in 1995 and has a particular interest in reservoir characterization. He is a member of the SEG and SEG Japan. [email protected]

For more information about the authors see, Geoscientist Directory at www.gulfpetrolink.com

Manuscript Received January 5, 2003

Revised June 30, 2003

Accepted September 1, 2003

Press Version Proofread by Authors March 30, 2004

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