petroleum systems of oman, charge timing and risks

AAPG Bulletin, v. 85, no. 10 (October 2001), pp. 1817–1845 1817

Petroleum systems of Oman:Charge timing and risksJ. M. J. Terken, N. L. Frewin, and S. L. Indrelid

ABSTRACT

After 35 years of exploration, creaming of the conventional playsin Oman is nearly complete, and consequently, the search has com-menced for new, less obvious plays. Many of the new opportunitiesoccur beyond the known hydrocarbon provinces and are consideredto have significant charge risks. To define these risks, extensive basinmodeling studies have been conducted in recent years.

Modeling and empirical data show that Mesozoic and Cenozoickitchen areas are restricted to western north Oman, the only areascurrently buried at their maximum temperature. Large parts ofnorth and central Oman depend on lateral migration from thesekitchens for their charge. Progressive uplift of the east flank andbasin inversion since the middle Paleozoic provides favorable con-ditions for long-distance migration in the post-Carboniferous inter-val. In central Oman, geochemical tracer molecules (benzocarba-zoles) suggest that a north-south–trending, reactivated basementgrain has funneled charge up to 300 km southeastward. Charge risksincrease in the deeper sequence, in which eastward migrating hy-drocarbons have to traverse the Ghaba salt basin, a pronouncedsyncline at depths greater than 3 km. The south Oman salt basin iscurrently cool because of shallow depths and hydrodynamic fluid-flow activity. The shallow post-Cambrian reservoirs rely on storageof early (Cambrian–Ordovician) charge by the Ara salt (Cambrian)sequence, followed by release of hydrocarbons as the salt edge re-treats through time.

Basin modeling has outlined the extent of the different petro-leum systems and provided us with risk maps to guide our nextexploration phase. It has revitalized some of the mature plays, forinstance the Gharif Formation, where oil exploration is now fo-cused along Late Cretaceous and Tertiary migration paths. Deepersections are envisaged to have significant scope for gas.

INTRODUCTION

After almost four decades of intense exploration, many of the tra-ditional plays in the Petroleum Development Oman (PDO) acreage

Copyright �2001. The American Association of Petroleum Geologists. All rights reserved.

Manuscript received September 7, 1999; revised manuscript received October 23, 2000; final acceptanceJanuary 8, 2001.

AUTHORS

J. M. J. Terken � NAM Business Unit GasLand, Beekweg 31, Postbus 1, 7760AASchoonebeek, Netherlands;[email protected]

Jos J. M. Terken joined Shell in 1982 and hasworked in the Netherlands, Brunei, NewZealand, and Indonesia. In 1993 he joinedPetroleum Development Oman (PDO) as asenior review geologist/basin modeler in theregional studies team. In close cooperationwith the geochemistry group he modeled andmapped the petroleum systems of Oman.Since November 1999 he has been a seniorproduction geologist for the NederlandseAardolie Maatschappij in the Netherlands. Josreceived an M.Sc. degree in geology/sedimentology from the University of Utrechtin 1982.

N. L. Frewin � Petroleum DevelopmentOman; [email protected]

Neil L. Frewin is currently a member of ShellInternational’s technology innovation team inthe Netherlands. Before 2001, he was seniorpetroleum geochemist for PDO, where he ledthe hydrocarbon modeling group. Prior tobeing posted to PDO in 1997, he worked forShell International in the Netherlands as aresearch geochemist. He holds a B.Sc. degreein geology from the University of Wales and aPh.D. in geology/geochemistry from theUniversity of London. Neil spent apostdoctoral year researching biomarkertechnologies at Delft University and NIOZ, theNetherlands.

S. L. Indrelid � Petroleum DevelopmentOman; [email protected]

Sarah L. Indrelid joined Shell in 1993. Prior tobeing posted to PDO in 1998, she worked forShell International in the Netherlands as aresearch geologist on thermal and pressuremodeling. After one year as senior basinmodeler in the hydrocarbon modeling groupshe is currently a senior production geologistfor PDO. She holds a B.A. degree in naturalsciences from the University of Cambridgeand a Ph.D. in geology from the University ofOxford.

1818 Charge Timing and Risks in Petroleum Systems of Oman

(Figure 1) are strongly creamed (Figure 2a), and in recent years thesearch has commenced for other less obvious plays and subtler trapstyles. In north Oman, this led to exploration for structural trapsalong Ara salt diapir stocks in the Early Cambrian Ghaba salt basin(Faulkner, 1998) and for stratigraphic traps in turbidites of the Up-per Cretaceous Fiqa Formation and alluvial/coastal deposits of theLate Ordovician–Early Silurian Upper Haima Supergroup (Ghu-dun and Safiq formations) (Figure 3) in the Late Cretaceous fore-land basin and the Early Cambrian Fahud salt basin, respectively(Partington et al., 1998). In south Oman, interest was renewed inintra-Ara salt stringers in the south Oman salt basin of Early Cam-brian age (Boserio et al., 1995; Amthor et al., 1998a; Reinhardt etal., 1998). Many of these frontier opportunities occur beyond theknown hydrocarbon provinces and are considered to have signifi-cant oil and gas charge risks (Figure 2b). To define the risks in newplays and determine the remaining scope in our conventional playportfolio, extensive basin modeling studies have been conducted inrecent years (Terken, 1999; Terken and Frewin, 1999).

Comprehensive hydrocarbon habitat studies have been carriedout for 20 years and concentrated initially on the Early Cambriansouth Oman salt basin (Al-Marjeby and Nash, 1984). Here, aunique habitat was recognized across the east flank of this basin(Figure 1), which was only fully understood once fission track (FT)data (Gleadow et al., 1983; Green et al., 1989) resolved the thermalhistory (Visser, 1991; Indrelid and Terken, 2000). The data showedthat hydrocarbon generation from presalt Precambrian and intrasaltLower Cambrian source rocks predated final entrapment by up to400 m.y. It also highlighted the factor of Ara salt dissolution dueto hydrodynamic fluid-flow activity on trap formation and retreatof the salt edge on charge timing (Konert et al., 1991). With thediscovery of large gas and condensate reserves in the Early Cam-brian Fahud and Ghaba salt basins (Figure 1) in the early 1990s(Figure 2), the focus of these studies shifted to north and centralOman.

In recent years, increased computer power and availability ofregional seismic maps have permitted us to model the burial andthermal histories in three dimensions and to calibrate the modelsusing FT data and maturity estimates derived from marine sourcerocks, solid hydrocarbons, and oils. Integration with our geochem-ical knowledge of source rocks and recovered or produced hydro-carbon samples allowed us to locate the paleo and recent “hydro-carbon” kitchen areas and to retrace the hydrocarbon migrationroutes. Mapping the extent of the different petroleum systems hasoutlined and confirmed the areas with higher charge risks, an im-portant economic outcome of this investigation. Meanwhile, ourunderstanding of diagenetic sequences in reservoirs (Amthor et al.,1998b), of the current temperature and salinity fields (Lamki andTerken, 1996), and of the structural history (Loosveld et al., 1996)highlighted the importance of hydrodynamic fluid-flow activityon oil quality and hydrocarbon migration. This understanding al-lowed the mapping of areas affected by oil biodegradation and the

ACKNOWLEDGEMENTS

We acknowledge the contributions of variousPDO geoscientists, notably Ramon Loosveld,Peter Nederlof, Mike Naylor, Jean Borgomano,Wiekert Visser, Geert Konert, Jeroen Peters,Joachim Amthor, Paul Tricker, and PascalRichard. We thank the Newcastle ResearchGroup, in particular Steve Larter and BazBennett, for geochemical analyses and discus-sions. Jeremy Dahl and Mike Moldowan atStanford University are acknowledged for dia-mondoid analyses. Geochemists at Shell’s re-search and technology group (SEPTAR) in theNetherlands are acknowledged for numerousreliable analyses over 20 years and continuingdiscussions on Oman’s petroleum systems. Inparticular, we thank Math Kohnen, JanKleingeld, Kees Kommeren, and JohanBuiskool Toxopeus for their extensive input.Christopher Kendall, R. Scolaro, and especiallyGerard Demaison are thanked for their con-structive reviews. We wish to thank the Minis-try of Oil and Gas of the Sultanate of Omanfor permission to publish this article.

Terken et al. 1819

Figure 1. Location map with structural setting superimposed on top Nafun Group (Buah Formation, late Precambrian) depth map.The map shows the different basins, map areas, and cross sections discussed in the text. Contours are in kilometers.


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Figure 3. Stratigraphy, petroleum geology, and oil types of Oman.

mapping of the stratigraphic levels that endured highformation temperatures where oil has cracked to gas.This article summarizes multiple investigations thatpermitted us to identify and quantify the different pe-troleum systems and helped determine the remaininghydrocarbon potential in our conventional portfolio aswell as the exploration potential of the frontier plays.The three-dimensional (3-D) basin modeling was car-ried out using Shell’s proprietary software IBS (Her-mans et al., 1992; Giles et al., 1999).

REGIONAL SETT ING AND STRATIGRAPHY

Oman lies along the eastern margin of the Arabianplate (Figure 1) and was until the Early Triassic part ofthe Gondwana continent (Loosveld et al., 1996). Thegradual breakup of this huge landmass has greatly in-fluenced the tectonic setting and is responsible forthe many unconformities found in the stratigraphy(Figure 3).

The oldest sequence is the prerift Abu Mahara andNafun succession of the late Precambrian, which is pre-dominantly made up of siliciclastics and carbonates

(Gorin et al., 1982; Hughes-Clarke, 1988). Tectonismduring the Early Cambrian resulted in the formationof fault basins filled with thick Ara Group evaporites,siliceous source rocks, shales, and late synrift clasticsof the Lower Haima Supergroup (Husseini and Hus-seini, 1990; Boserio et al., 1995; Droste, 1997). Innorth Oman, onlapping marginal marine siliciclasticsediments with occasional limestones of the LateCambrian–Early Silurian Upper Haima Supergroupoverlie this rift sequence and represent the postrift sag-ging in the Ghaba salt basin. In south Oman, the UpperHaima sediments are largely absent because basin con-traction caused uplift of the basin’s east flank and ero-sion during the Ordovician. Uplift and erosion of theeast flank spread to the north during the Devonian–Carboniferous, resulting in a major stratigraphicunconformity.

Because of this unconformity, the Haima Super-group (Middle Cambrian–Early Silurian) sediments areunconformably overstepped by the glacial, continental,and shallow marine siliciclastics of the Permian–Carboniferous Haushi Group and finally by fully ma-rine transgressive carbonates of the Akhdar Group(Late Permian–Early Triassic). Uplift and erosion of


the latter sediments in the north and east have beenassociated with renewed rifting and thermal doming.This ultimately led to the separation of the Iranian andLut cratons from the Gondwana continent (Blendingeret al., 1990). Tilting of the flanks caused down-to-the-basin gravity gliding and renewed inversion of theEarly Cambrian salt basins. In the Ghaba salt basinproper, this led to salt doming above reactivated base-ment fault zones. In south Oman, it triggered extensivesalt dissolution and development of a peripheral syn-cline along the east flank of the salt basin. Platformcarbonates are characteristic of the Mesozoic Sahtan,Kahmah, and Wasia groups and represent a passivemargin succession that bordered the neo-Tethys Ocean(Hughes-Clarke, 1988; Le Metour et al., 1995). Thistransgression reached south Oman only in the middleCretaceous, resulting in the deposition of the NahrUmr Formation (lower Wasia Group).

Opening of the Atlantic Ocean during the LateCretaceous led to closure of the neo-Tethys Ocean,obduction of oceanic crust, and finally to southwardthrust stacking in the Oman Mountains (Bechennec etal., 1995; Tj. Peters et al., 1995; Loosveld et al., 1996).The foredeep that developed in front of the orogen wasfilled with deep-marine Fiqa shales of Late Cretaceousage that onlap the peripheral foreland bulge in thesouth (Boote et al., 1990; Warburton et al., 1990). De-velopment of a new subduction zone offshore south-east of Iran brought temporary relaxation during theearly Tertiary and also Eocene Umm er Radhuma lime-stone deposition (Le Metour et al., 1995). Forelandbasin sedimentation resumed, however, when conti-nent-continent collision occurred along the Zagros su-ture during the middle Tertiary. Compression since themiddle Tertiary has caused folding and uplift of theOman Mountains and further tilting of the east flankof the salt basins, which has led to renewed down-to-the-basin gravity gliding and active Lower CambrianAra salt diapirism (Loosveld et al., 1996).

Finally, in south Oman, the Gulf of Aden rift be-gan developing during the early Oligocene followinglate Eocene uplift (Bott et al., 1992). Sea-floor spread-ing began in the late Miocene and led to the separationof the Arabian craton from the African continent.

DATABASE AND METHODOLOGY

Our copious data sets document several distinct petro-leum systems. Type, quality, and distribution of oils,gases, and source rocks are in most cases well defined

and supported by continuing geochemical researchover many years. The basic techniques have been de-scribed by Lijmbach et al. (1983) and Peters and Mol-dawan (1993). Recent advances in geochemistry, suchas the use of benzocarbazoles as indicators of relativemigration distances (Larter et al., 1996), have permit-ted us to retrace migration routes back to their sourceareas. This highlighted in one case the importance oflong-distance migration in Oman (Terken and Frewin,1999). New biomarkers, such as triaromatic steroidsand dinorhopane, have helped us to discriminate be-tween the different oils and source rocks within the latePrecambrian Nafun and Early Cambrian Ara salt-richsequences in south Oman (M. E. L. Kohnen, 1998,personal communication).

An extensive FT database, vitrinite reflectance es-timates, and detailed diagenetic sequence studies inreservoirs (Amthor et al., 1998b; K. Juhasz-Bodnar etal., 1999, unpublished data) have provided time/temperature and time/depth constraints to recon-struct the burial and thermal histories.

Kinetic experiments by Shell Research demon-strated significant differences in activation energies be-tween late Precambrian and Early Cambrian sourcerocks that allowed us to accurately model their sepa-rate generation histories. In north Oman, paragenesisstudies of bitumen and pyrobitumen in reservoirshelped to unravel the early charge history (Huc et al.,2000). Reservoir salinities in some 50 wells, and 1500(corrected) formation temperatures in more than 500exploration wells were used to outline the current hy-drodynamic fluid-flow activity (Lamki and Terken,1996). This present-day pattern was combined withour knowledge of the tectonic evolution to recon-struct the historical fluid-flow evolution within therecognized petroleum systems.

Extensive two-dimensional (278,000 km) and3-D (33,000 km2) seismic data sets provided the 11regional structural maps that were used together with3 reconstructed depth maps that considered maxi-mum burial levels prior to major Paleozoic, Mesozoic,and Tertiary erosional events (Figure 3). Early Cam-brian Ara salt isopach and heat-flow maps were re-constructed for successive time slices to model the saltmovement and thermal flux histories. The present-daygeothermal field, which is controlled by foreland basindevelopment in the north and rifting in the Gulf ofAden in the south, was used to reconstruct the LateCretaceous to Holocene thermal history (Lamki andTerken, 1996) In contrast, the early Paleozoic thermalhistory reflects a rifting phase in the Early Cambrian

Terken et al. 1823

Figure 4. Different oil typesof Oman based on C27-steranecontent and total oil carbon iso-tope value. Experiments revealmixing occurs along lineartrends between oil end mem-bers. Coding in circles refers tothe oil composition of the ana-lyzed mixtures. Only Natih oil(Cretaceous), Shuaiba/Tuwaiqoil (Jurassic), and Q, and northOman Huqf oils (both latePrecambrian–Early Cambrian)have been used in the mixingexperiments. Cracked oils (latePrecambrian–Early Cambrian),B oil (possibly Silurian), andsouth Oman Huqf oil (latePrecambrian–Early Cambrian)show only limited mixing andwere excluded.

Ghaba salt basin and south Oman salt basin (Fig-ure 1), which was also considered in the thermalmodeling.

PETROLEUM GEOLOGY OF OMAN

Determination of Genetic Oil Types, Mixing, andAlteration

In the identification of charge risks in frontier areasand remaining prospectivity in mature basins, sourcerock/oil correlations and discrimination between ge-netic oil families are key elements because they formthe foundation for the description and mapping ofdistinct petroleum systems. These elements are par-ticularly important in Oman because several sets ofmajor source rocks exist, ranging in age from Precam-brian to Cretaceous (Figure 3); all have contributedto the charging of economically significant oil fields.Five end-member oil families have been discrimi-nated through differences in molecular and isotopicfingerprints (Figure 4), (Al-Ruwehy and Frewin,1998). Two distinct oil families are derived from thelate Precambrian–Early Cambrian Huqf Supergroup

(the Huqf oils and Q oils). Two oil families are gen-erated from Mesozoic source rocks, Late Jurassic(Callovian–Kimmeridgian) and middle Cretaceous(Aptian) Shuaiba/Tuwaiq oils and middle Cretaceous(Cenomanian–Turonian) Natih oils. The only oilfamily that cannot be linked to a specific source rockis the so-called B oil family. In identifying these dis-tinct oil families and combining geochemical infor-mation with the geological framework and detailedcharge modeling, it is possible to outline the strati-graphical and geographical extent of the petroleumsystems of Oman (Figure 5). This exercise can delin-eate broad exploration targets and rank them accord-ing to their economic charge potential.

The undisputed basic classification of Oman’shydrocarbons is commonly obscured by mixing ofthe different oils during secondary migration fromtheir respective source areas along long and some-times complex migration paths. In-house experi-ments by Shell Research have revealed that mixingbetween end members occurs along linear trends.Contributions from several original oil types in co-sourced reservoired oils can be effectively estimatedusing modern geochemical investigative techniques(Figure 4).


Figure 5. Distributions of thedifferent oil types in Oman out-line the geographical extent oftheir petroleum systems. e.Prec.–L. Camb. � early Pre-cambrian to Late Cambrian.

Extract analyses of bitumen and microscopy stud-ies of pyrobitumen indicate that thermal cracking ofliquid hydrocarbons trapped in deeply buried reser-voirs and source rocks is a major contributor to the gasreserves found in north Oman. Furthermore it also in-dicates that cracked Huqf and Q oils are the main con-tributors to these gas accumulations (Huc et al., 2000).Light oils and condensates reveal partly or completelydegraded biomarker contents and indicate thermal

cracking of reservoired oils to commence at tempera-tures of around 130�C. Thermal cracking ultimately isexpected to cause a complete breakdown of liquid hy-drocarbons and generation of dry gas at temperaturesof around 180�C. Besides degradation and diminutionof the biomarker content in very light oils and conden-sates, thermal cracking also affects the total oil d13Cisotope value. It has been observed to drop from lighterthan �30‰ in Huqf and Q oils to around �26‰ in

Terken et al. 1825

light oils/condensates and even as low as �20‰ in drygas (Huc et al., 2000).

Existing Oil Families and Their Related Source Rocks

Huqf Oil Family (Derived from Late Precambrian–EarlyCambrian Source Rocks)The broadly named Huqf oil family is derived from latePrecambrian–Early Cambrian source rocks. They arecharacterized by a distinct C29-dominated sterane dis-tribution and can be subdivided into south Oman Huqfoils (around �36‰) and north Oman Huqf oils(around �34‰), based on differences in whole oild13C isotope values (Figure 4; Table 1). The lighterisotope values in the north could result from higher oilmaturities. Huqf oils are also characterized by a ho-mologous series of long-chain, methyl-substituted al-kanes (or so-called X compounds), which have beenidentified elsewhere in oils of late Precambrian age(Guit et al., 1995; Summons et al., 1998a, b).

Extract analyses indicate the Huqf oils to bemainly derived from Early Cambrian intrasalt sourcerocks of the Ara Group, but in places also from presaltNafun Group source rocks of late Precambrian age(Figure 3). Statistical evaluation of detailed biomarkerparameters by cluster analysis has permitted the sub-division of Huqf oils into three end members sourcedby, respectively, the Precambrian presalt Buah andShuram formations (Nafun Group), the Early Cam-brian intrasalt Al Shomou Formation (Ara Group), andthe U-Shale Formation (Ara Group). Rock-Eval anal-yses and measured activation energies indicate that in-trasalt siliceous Al Shomou Formation (or Athel sili-cilyte) source rocks generate large volumes of oil atrelatively low temperatures (Table 1). The organicmatter in these source rocks consists predominantly oftype II/I kerogen, and the total organic carbon (TOC)content measures up to 7%. Initial hydrogen indicesaverage around 600, but in places exceed 800 mg HC/g TOC. Thicknesses of these source rocks are variableand are known to range between 20 and 400 m (Bos-erio et al., 1995; Amthor et al., 1998a; Reinhardt etal., 1998). Most of the Huqf oils are sourced from thesesalt-associated carbonate and siliceous source rocks,and their extent is assumed to be constrained by theAra salt sequence itself. Calculations of the source po-tential index (SPI) of the Ara and Nafun source rocksshow the existence in the late Precambrian and EarlyCambrian of Oman of volumetrically important sourcerocks. The Al Shomou Formation, for which wehold a large database, is characterized by an SPI of 38 t Ta

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HC/m2, whereas the U-Shale features an SPI of 10 tHC/m2; together with the Shuram Formation (7 t HC/m2) these represent some of the richest source intervalsin the world (Demaison and Huizinga, 1994; P. Ned-erlof, 1998, personal communication).

In north Oman the distribution of Huqf-generatedoils is stratigraphically and geographically limited tothe central area, but in south Oman, Huqf oil occur-rences are widespread both stratigraphically and geo-graphically (Figure 5). In north Oman, the Huqf oilshave also migrated up into middle Cretaceous Shuaiba(upper Kahmah Group) carbonates below the regionalNahr Umr Shale (lower Wasia Group) seal (Figure 3).Furthermore, considerable oil reserves of Huqf oilshave also been found in the Permian Gharif fluvial andfluviomarine sandstones sealed by intraformationalshales or Khuff Formation (Akhdar Group, LatePermian–Early Triassic) muddy limestones. Bitumenstudies indicate that Huqf oils were once also en-trapped in currently deeply buried Haima (LateCambrian–Early Silurian) sequences, but these oilscracked to condensate and gas because of very deepburial during the Late Cretaceous and Tertiary (Hucet al., 2000). In the south Oman salt basin, Huqf oilsare found to occur in Precambrian–Tertiary reservoirsalong the east flank of the basin and within Early Cam-brian intrasalt carbonate and siliceous (silicilyte)stringer reservoirs in the central part of the basin (Ko-nert et al., 1991; Amthor et al., 1998a).

Q-Oil Family (Presumed to Be Derived from Source Rocks ofthe Late Precambrian–Early Cambrian Huqf Supergroup)The Q oils were originally named because of their“questionable” origin (P. Nederlof, 1999, personalcommunication). Oils from this family have distinctC27-dominated sterane distributions and intermediated13C isotope values of around �30.5‰ (Figure 4)(Grantham et al., 1987). In addition, Q oils feature ahigh tricyclic index compared with most other Omanoils and are further characterized by the presence of apeak of unknown chemical structure visible in the ster-ane (m/z 217) mass chromatogram (Figure 3). Thispeak is commonly noted as peak A (Richard et al.,1998; Terken and Frewin, 1999). In common with theHuqf oils (described previously), Q oils have a seriesof methyl-substituted alkanes that are generally quiteevident in gas chromatograms.

This combined geochemical evidence points to adistinctive source rock sequence for the Q oils in northOman, although it is probably a part of the latePrecambrian–Early Cambrian Huqf Supergroup. At-

tempts to link the Q oil directly to a source rock havefailed so far through lack of deep well penetrations innorth Oman. Biomarkers in these oils are characteristicof oils originating from type II/I structureless organicmatter. Furthermore, the biomarker patterns stronglysuggest that this oil is derived from a carbonate sourcerock deposited in a strongly evaporitic but not hyper-saline environmental setting (Grantham et al., 1987).The source of the Q oil, therefore, is suspected to belocated in Early Cambrian intrasalt or postsalt Arasource rocks (Figure 3). In well Shara South-1 in cen-tral Oman (Figure 1), extract analysis of an impreg-nation indicates mixed Q-type and Huqf-type hydro-carbons are present in the postsalt Dhahaban sourcerock (see Figure 3). In nearby well Haima-1 (Figure 1),core descriptions indicate this interval also representsa salt dissolution cap rock, which would suggest thatits distribution is limited to that of the Ara salt se-quence. Thickness of this unit is variable, ranging be-tween 20 and 500 m (Terken and Frewin, 1999). TheTOC contents range up to 8%, and initial hydrogenindices are high, averaging 600, and locally exceed 800mg HC/g TOC. The measured activation energies arevery similar to those of most other Huqf source rocksand range from 197 to 240 kJ/mol (Table 1).

Q oils occur mainly in the Permian Gharif For-mation of the Haushi Group in central and northOman (Figures 3, 5), but significant amounts have alsobeen found in the middle Cretaceous Shuaiba Forma-tion of the Kahmah Group on the other side of thesalt-structured core of the Ghaba salt basin (Terkenand Frewin, 1999). Q gases and condensates occur pre-dominantly in the early Paleozoic Haima Supergroup,mainly along the western margin of the Ghaba salt ba-sin (Figure 2). Reservoirs range in depositional settingfrom continental to deltaic and marginal marine(Droste, 1997) and are sealed by intraformational ma-rine shales.

B Oil Family (Enigmatic Character, but Potentially Sourcedfrom Untested Silurian Source Rocks to the West of Oman, orfrom the Cracking of Early Cambrian-Sourced Oils)B oils were named because of their indistinct or “back-ground” signature. They are the least understood of alloil families in Oman. No distinctive chemical attrib-utes link B hydrocarbons to a source. The oils are sim-ply characterized by relatively high C27 and C29 ster-ane abundances and typically have d13C isotope valuesof around �26 to �30‰ (Figure 3). Known B oil ac-cumulations are found in the Ghaba salt basin of northOman (mostly condensates � 50� API) and in west-

Terken et al. 1827

ernmost central Oman (mostly light oils � 40� API).Furthermore, noncommercial impregnations with a Bcharacter have also been observed elsewhere through-out Oman.

The source of the B oils is still under evaluation.The oils were originally considered to be a mix be-tween the salt-associated Huqf and Q end-member oils(a tentative explanation largely deduced from the ster-ane distribution and carbon isotope values); however,the steranes tend to be thermally degraded and lessabundant in the condensates. The presence of B hy-drocarbons, either as light oils (�50� API) or as im-pregnations, could at first glance lead us to suggest thatthey are partially cracked mixtures of Early Cambrian–sourced oils, especially because these oils are found inpre-Silurian Haima reservoirs. Indeed, a detailed anal-ysis of many condensates having a B character in theGhaba salt basin of north Oman shows clear thermalcracking characteristics. The extent of thermal crack-ing can be estimated from the abundance of methyl-diamantanes, diamondoid structures that are resistantto the thermal cracking process, relative to stigmas-tane, a C29 sterane biomarker that is thermally unsta-ble (Dahl et al., 1999). The extent of cracking (derivedfrom diamondoid data, as described by Dahl et al.[1999]) is shown in Figure 6 for several condensatesrelative to their corresponding reservoir temperature.Oils described as B type have been selected from theGhaba salt basin and western central Oman. The oilsfrom the Ghaba salt basin are apparently highlycracked compared with the western central Omansamples.

In terms of source of the Ghaba basin condensates,the lack of methyl-substituted alkanes (X compounds)

and of other distinctive biomarkers characteristic of theHuqf and Q families would tend to negate the hypoth-esis that these oils are originally derived from EarlyCambrian salt-associated Huqf and Q source rocks. Itshould be noted, however, that the lack of methyl-substituted alkanes in an oil does not necessarily pre-clude an infra-Cambrian origin. Indeed, these com-pounds do not occur uniformly in extracts fromthroughout Huqf source rock sequences, there beingseveral organic-rich shales in which the compounds areabsent. Furthermore, other infra-Cambrian oils do notcontain X compounds. For example, an oil from theBaghewala-1 well in India was found not to containthese compounds (K. E. Peters et al., 1995).

For the lower-API oils of westernmost centralOman, the remigration of mature Huqf and Q hydro-carbons can be demonstrated using charge modeling(see section Mapping of Petroleum Systems by Gen-eration and Migration Modeling); however, the Safiq/Qusaiba Member shale of Silurian age (Upper Haimain Figure 3) in the Rub’ Al-Khali basin in eastern SaudiArabia (Figure 1) is seen as an alternative candidatesource rock for these B-type hydrocarbons. This sug-gestion is not unreasonable given the location of theSahmah and Rija B-oil accumulations in western cen-tral Oman (Figure 5) relative to the distribution ofmature Silurian Qusaiba source rock facies in SaudiArabia (Milner, 1998; Jones and Stump, 1999).Furthermore, the oils in these accumulations show noevidence of thermal cracking (determined from rela-tive diamondoid abundance) (Figure 6). Marginal (i.e.,thin) Qusaiba Silurian shales with hydrocarbon gen-erating potential (TOC measured at 3.25 wt. %, hy-drogen indices up to 543 mg HC/g TOC) have also

Figure 6. Difference in extentof cracking shown only for oilsclassified as B oils in westerncentral Oman in the Rija andAydan fields (see Figure 1) andin the Saih Rawl, Barik, andMabrouk fields in the Ghabasalt basin.


been penetrated within Oman. Molecular typing of anextract from this thin shale (i.e., in the Fawwara-1well in Figure 1) and determination of its correlationwith various B oils from Oman and Saudi Arabia havebeen tentatively achieved. Similarities are noted insterane distribution, carbon isotopes, pristane/phy-tane index, and other molecular typing results; how-ever, we need a wider source rock database to firm upthis tentative correlation.

Despite these advances, the origin of the B-typehydrocarbons is still not fully understood. Impregna-tions having sterane and isotope distributions similarto those of the B-type oils, but also having elevatedtriaromatic dinosteroid levels (commonly observed inpost-Triassic source rocks), are also found throughoutOman. Although such unexpected components areexpected to be the result of contamination by drillingfluid additives, whose signature is enhanced by thelow abundance of hydrocarbons associated with im-pregnations, those mixed messages tend to confuseour appraisal of the B-type oil family. Furthermore,the possibility of cosourcing from sources of differentages cannot be entirely eliminated.

Shuaiba/Tuwaiq Oil Family (Originating from Late Jurassic[Callovian–Kimmeridgian] and Middle Cretaceous [Aptian]Source Rocks)Shuaiba/Tuwaiq oils commonly display whole-oild13C isotope values of around �26.5‰ and aboutequal amounts of C28 and C29 steranes, but loweramounts of C27 (Figure 3).

Shuaiba/Tuwaiq oils are sourced by type II/I ma-rine source rocks (Lijmbach et al., 1992). Geochem-ically, minor variations can be observed between oilsfound in the Shuaiba and Tuwaiq, which suggestslight differences exist between source rocks withinthe Mesozoic Sahtan/Kahmah and Thamama groups.The most likely source rocks are the Bab Member inthe Shuaiba Formation and the Diyab (Hanifa) For-mation (Taher, 1997). Both source rocks were depos-ited in intracratonic basins, which covered most of theAbu Dhabi emirate in the United Arab Emirates(UAE) and may extend into northern Oman. TheTOC values measured in the UAE exceed 4 wt. % byweight, and the thickness of both source intervalsranges from 30 to 100 m. In the foreland basin of theUAE, the TOC in the Thamama Group drops grad-ually and averages only 1.4 wt. % near the Oman bor-der where most of the organic matter is overmatureand has only minor residual gas potential (Taher,1997). The high maturity is due not only to greater

burial, but also to significantly higher formation tem-peratures related to the hydrodynamic fluid-flow re-gime in the foreland basin (Lamki and Terken, 1996).Initial hydrocarbon yields may have been as high as800 mg HC/g TOC (Taher, 1997). The actual mea-sured activation energies for the Hanifa source rocksare in the range of 192–229 kJ/mol (Table 1). Becauseboth source rock intervals are very similar in charac-ter, a similar range was also assumed for the Shuaibasource rock.

Shuaiba/Tuwaiq oils are restricted to northwest-ern Oman but are common in the UAE (Lijmbach etal., 1992). In Oman, these oils occur predominantlyin the Late Jurassic Tuwaiq and middle CretaceousShuaiba formations.

Natih Oil Family (Derived from Middle Cretaceous[Cenomanian to Turonian] Wasia Group Source Rocks)Natih oils are characterized by a relatively high C27

sterane abundance and a d13C isotope value ofaround �27‰. The C27 sterane percentage is gen-erally around 35% and exceeds the amount of C28,which, in turn, is higher than the amount of C29

(Figure 3).The oils are sourced by marine type I/II source

rocks within the Natih Formation. Evaluation of allwell penetrations shows the source rock facies to berestricted to western north and central Oman (Ter-ken, 1999). Deposition most likely occurred in a re-stricted possibly oxygen-depleted intracratonic marinebasin on the Arabian craton that was connected to theopen (Tethys) ocean in the northwest (Murris, 1980).The source rock facies occurs at two levels, and thecombined source interval commonly exceeds 50 mand is excellent in quality (van Buchem et al., 1996).The TOC values range up to 15%, but average around5%. Hydrocarbon indices may be as high as 800 mgHC/g TOC (Terken, 1999). Activation energies forthe source rock are assumed to range between 192and 229 kJ/mol (Table 1), values typical of high-quality marine type I/II source rocks.

Nearly all Natih oil is reservoired within the NatihFormation itself. This carbonate sequence is Ceno-manian–Turonian in age. Deep-marine shales of theLate Cretaceous Fiqa Formation onlap its top and pro-vide an excellent seal in most parts of north Oman.Natih oils are restricted to a small area in central northOman, a distribution that is structurally controlled tothe south by the peripheral bulge of the foreland basinand to the east by the deformed core of the Ghabasalt basin (Terken, 1999).

Terken et al. 1829

Mapping of Petroleum Systems by Generation andMigration Modeling

For details of the methodology used, the reader is re-ferred to the Appendix.

Late Precambrian and Early Cambrian Huqf and Q PetroleumSystems in North OmanBurial and thermal modeling of the presalt Nafun, in-trasalt Ara, and postsalt Dhahaban intervals, thesources of both Huqf and Q oils, indicate early oil gen-eration during the Paleozoic in large parts of Oman(Figure 7). In the center of the Ghaba salt basin, thesesequences expelled most of their hydrocarbons duringthe deposition of the Haima Supergroup during theearly to middle Paleozoic (520–350 Ma). Along thewestern margin of the Ghaba salt basin, the remainingoil and gas potential was expelled during AkhdarGroup (Permian) deposition (260–230 Ma), when anew burial maximum was reached. In the Fahud saltbasin, the Nafun and Ara (late Precambrian and EarlyCambrian) source rocks expelled most of their oil dur-ing Akhdar Group (Permian) deposition. Only theshallowest source rocks of the postsalt Dhahaban in-terval continued to generate oil into the Tertiary, andit is the only Cambrian source rock that remains in thehydrocarbon generation window today, although itnow generates only dry gas.

In-house migration modeling shows that the earlyPaleozoic charge from the northerly Ghaba salt basinspread across this sag basin to its flanks (Figure 8)and either accumulated in Haima Group (Middle

Figure 7. Oil generation histories for the different source rocks in Oman. SR � source rock.

Cambrian–Early Silurian) closures or reached the sur-face. Middle Paleozoic erosion brought these earlytrapped hydrocarbons within reach of meteoric water,causing oil biodegradation and formation of tar sandsbefore late Paleozoic deposition. Deep reburial andhigh formation temperatures since the Late Cretaceoushave turned the early tar into pore-filling pyrobitumensand substantially reduced the reservoir quality in theseearly traps (Figure 9). They may still, however, holdsome secondary charge potential for gas from thermalcracking (Huc et al., 2000). Charges expelled from thewestern Ghaba basin margin and Fahud salt basin dur-ing the late Paleozoic to Late Cretaceous are inter-preted to have migrated laterally eastward within theHaushi Gharif Formation (Permian) reservoirs towardthe tilted east flank of the basin (Terken, 1999)(Figure 10).

After the Late Cretaceous, migration in northOman was strongly influenced by the developmentof the peri-Tethys foreland basin. The present-dayoil-type distribution suggests that Huqf (latePrecambrian—Early Cambrian) oils, which were gen-erated in the northern half of the Fahud salt basin,migrated initially toward and along the peripheralbulge of the foreland basin (Figures 10, 11, 12). Thisbulge is somewhat interrupted across the Fahud saltbasin because of uplift of its east flank and theassociated inversion of the Ghaba salt basin. Thiscaused a shift of the depocenter in the foreland basintoward the northwest. Modeling shows that hydrocar-bons migrated mainly toward the east at Haima (LateCambrian–Early Silurian) and Haushi (Permian)


levels; however, migration proceeded both toward theeast and the west in shallower Akhdar (Permian), Sah-tan (Jurassic), and Wasia (Cretaceous) reservoirs (Fig-ures 10, 11). Vertical migration occurred along exten-sional faults associated with the prograding peripheralbulge.

Migration from the southern half of the Fahud saltbasin within the Gharif Formation of the Haushi (Per-mian) Group initially progressed also toward the eastbut shifted gradually southward during the Late Cre-taceous and Tertiary (Figures 11, 13). This shift in di-rection has been linked to the advance of the tectonic

Figure 9. Old oil traps westof the coarse dashed line wereaffected by early biodegrada-tion and may be filled withpore-filling bitumen. Oil crack-ing and formation of pyrobitu-men due to high formationtemperatures most likely haveoccurred in the gray-patternedarea. The eastern part of theGhaba salt basin has a signifi-cantly higher charge risk thanthe western part in the pre-Haushi sequence. (Location ofthis map is shown on Figure 1.)Figure 8 shows the early kitch-ens and migration paths in thisarea, whereas Figure 10 (fromYibal to the east flank) showsthe present-day generation ar-eas and migration paths.

Figure 8. Kitchen area andmigration style in the Ghabasalt basin during the middle Pa-leozoic (400 Ma). (The locationof this line is shown onFigure 9.)

Terken et al. 1831

front in northern Oman and the southward expansionof the Mesozoic foreland basin across and over the Fa-hud salt basin. Subsidence caused the regional tilt toincrease and also a shift to a northerly azimuth.

Use of benzocarbazoles as geochemical tracer mol-ecules (Larter et al., 1996) has permitted an estimationof the relative lateral migration distances for the dif-ferent accumulations of Q oil (Early Cambrian–sourced). Benzocarbazoles are polar compounds,which tend to selectively partition between oil, water,and mineral surfaces during oil migration; thus ben-zocarbazole ratios have been successfully used as mo-lecular indicators of relative oil migration distance(Larter et al., 1997). A plot of benzocarbazole ratiosagainst northing highlights a substantial migration dis-tance of some 300 km (Figure 13). This finding allowedus to retrace the origin of the Q oils to the southernpart of the Fahud salt basin and also to a rim basinpresent along the western margin of the Ghaba salt

Figure 10. West-northwest–east-southeast cross section across north Oman showing the Shuaiba/Tuwaiq petroleum system in theforeland basin and north Oman late Precambrian–Early Cambrian Huqf and Q petroleum systems in the Fahud and Ghaba salt basins.Hydrocarbons generated on the Fahud salt basin initially rise vertically and subsequently migrate to the east at Gharif level and tothe east and west at Shuaiba level. Note that at the deeper Haima level hydrocarbons fail to cross the deep syncline in the Ghabasalt basin. Note also the limited extent of the Shuaiba/Tuwaiq petroleum system. Thermal cracking of oil to condensate and gas isassumed to occur at temperatures in excess of 130�C. (For stratigraphic legend see Figure 3; SR � source rock.)

basin (Richard et al., 1998; Terken and Frewin, 1999).North-south–oriented structural trends related to re-activated basement faults together with a favorable hy-drodynamic regime and effective top seals (intrafor-mational Gharif shales and the thick Khuff Formation)facilitated the observed long-distance Q-oil migrations.

Migration modeling of the Huqf-type and Q-typeoil distributions in north Oman has permitted a sub-division of the Fahud salt basin into three distinctsource areas, or hydrocarbon kitchens: (1) a westernpart that is regarded as the source of mainly pure Huqfoils, (2) a southern kitchen that sourced only Q-typeoil, and (3) an eastern kitchen that has generatedmostly Huqf-dominated mixtures of both types of oils(Figure 12).

The Huqf petroleum system of north Oman hasbeen genetically classified as a normally charged, ver-tically drained, fault-controlled high-impedance petro-leum system, whereas the Dhahaban (Q) system of


north Oman immediately above the salt is thought torepresent a normally charged, foreland-type, laterallydrained, low-impedance petroleum system (Figure 14)(Demaison and Huizinga, 1994).

Late Precambrian to Early Cambrian Huqf Petroleum Systemof South OmanApatite fission track analyses data indicate that maxi-mum burial temperatures in south Oman were reachedduring deposition of the Haima Supergroup (MiddleCambrian–Early Silurian) (see Appendix) (Indrelidand Terken, 2000) and that, as in the Ghaba salt basinto the north, oil generation occurred mostly during theearly Paleozoic (Figure 7) (Konert et al., 1991; Visser,1991). This suggests intermediate storage, by the ex-cellent quality salt seal, followed by remigration of oilinto shallower reservoirs. Early expelled oil was prob-

Figure 11. Cross section from the foreland basin in the north across central Oman to the northern part of the south Oman saltbasin showing the middle Cretaceous Natih, the late Precambrian–Early Cambrian north Oman Huqf, Q, and south Oman Huqfpetroleum systems. Hydrocarbons generated in the Fahud salt basin initially rise vertically and migrate to the east and south at Ghariflevel. Oil may have been initially stored at the deeper Haima level and remigrated 300 km to south Oman after gas charge becauseof oil-cracking–caused spillage in the Late Cretaceous and Tertiary. Note the limited extent of the Natih petroleum system, which isbounded by the Fahud fault in the south. Thermal cracking of oil to condensate and gas is assumed to occur at temperatures inexcess of 130�C. (For stratigraphic legend see Figure 3; SR � source rock.)

ably initially trapped in Nafun fault blocks sealed byAra salt and/or in carbonate and silicilyte stringers en-cased in Ara salt (Figure 15). The seals of these trapswere breached during the basinward retreat of the saltedge, and the oils were released. Salt dissolution andtrap formation in the east flank occurred in steps be-ginning with the onset of tilting in the late Paleozoic.Ara salt most probably once covered the whole of thebasin’s east flank in south Oman, and where the salthas dissolved out one can observe, on seismic, rem-nants of the intrasalt facies and Dhahaban cap rocksresting on top of the presalt Nafun sequence(Figure 16).

Several Haushi (Permian)/Haima (Middle Cam-brian–Late Silurian) reservoired accumulations espe-cially in the upflank areas were truncated and exposedto the surface during the Early Cretaceous erosion

Terken et al. 1833

phase, with consequent loss of oil to the surface. Newtraps were formed during Late Cretaceous and Tertiarysalt dissolution phases, and hydrocarbons were releasedfrom successively unroofed early Paleozoic Huqf traps.This sequence of events can explain the presence ofHuqf oils in much younger reservoirs, despite the factthat generation is thought to have occurred much ear-lier. In addition, new accumulations were locallybreached by faulting or tilting, which gave rise to ver-tical remigration of oil into Cretaceous Natih andUmm er Radhuma reservoirs, leaving tarry oil deposits

or oil residues at Haima (Middle Cambrian–Late Si-lurian) and Haushi (Permian) levels (Konert et al.,1991).

The distribution of the different Huqf-generated(late Precambrian—Early Cambrian) oils shows a goodrelationship with the lithofacies map of the intrasaltsequence (Figure 15). It strongly suggests that mostmigration along the east flank has a vertical component(Figure 16). Oil gravities range widely from about 10to 35� API, and tarry occurrences are common. Thelow gravities may be related not only to early expulsion

Figure 12. Basin modelingsuggests Mesozoic and Tertiarykitchen areas to be restricted tothe Fahud salt basin and fore-land basin. Oil types in thefields are raster coded, andmodeled migration paths areshown. SR � source rock.


of immature oil from carbonate- and silica-rich sourcerocks, but also to subsequent biodegradation by hydro-dynamic fluid-flow activity. The south Oman Huqf pe-troleum system is interpreted to be a supercharged and(prior to salt dissolution) laterally drained, low-impedance petroleum system (Figure 14).

Hypothetical B Petroleum System in Central OmanCondensates in pre-Silurian Haima clastic reservoirs ofthe Ghaba salt basin are most likely the result of in-reservoir thermal cracking of predominantly Q-typeoils (Table 2). An alternative hypothesis to explain theoccurrence of B-type oils only in the most recent, lateTertiary migration paths (Figure 12) is the existence ofa mature Paleozoic shale rather than a carbonate sourcerock in the southern part of the Fahud salt basin; how-ever, the hypothetical Paleozoic shale must be mod-eled using a significantly higher activation energy thanthat of the carbonate Huqf source rocks to satisfy thischarge mechanism timing (Table 1). Another proposed

Figure 13. Relative oil migra-tion distances can be estimatedfrom geochemical tracer mole-cules. Analyses of 18 (latePrecambrian–Early Cambrian)Q oils suggest one kitchen areaimmediately to the west of SaihRawl in a small rim basin andanother in the southern tip ofthe Fahud salt basin. Youngestmigration paths are used by Boils and cracked oils.

hypothesis is remigration from breached or gas-charged structures of earlier, thermally cracked Huqfand/or Q oils. This mechanism cannot be excluded atthis time.

The generation modeling of a Silurian QusaibaMember source for these B oils in westernmost centralOman has not been undertaken for this article, pri-marily because of the lack of data on the westernmargin of Oman and the eastern margin of SaudiArabia. Milner (1998), however, recently carried out amaturity mapping exercise using BasinMod; well AlHashman-1 was used for thermal calibration. Thiswork demonstrated that the Safiq-equivalent QusaibaMember may be of middle-late maturity west ofOman. This mapping suggests that oil may have lat-erally migrated into westernmost central Oman sinceits Late Cretaceous generation. This Silurian sourcerock was intersected in the Oman well Fawwara-1 andwas found to be immature to just mature for hydro-carbon generation.

Terken et al. 1835

The B petroleum system has been tentatively clas-sified, if the oils are derived from the Qusaiba sourcerock, as an undercharged, laterally drained, low-impedance system, and, in case the condensates arederived from thermally cracked Huqf and Q oils, asan undercharged, vertically drained, high-impedancesystem.

Shuaiba/Tuwaiq Petroleum System of North OmanThermal modeling of Late Jurassic and middle Creta-ceous source rocks in the UAE (Taher, 1997) andOman (J. M. J. Terken, 1996, unpublished data) showsthat oil generation (Figure 7) started in the Late Cre-taceous in the Diyab (Hanifa) Formation and in thePaleocene in the Shuaiba Formation (Bab Member).Currently, Diyab source rocks are, where present inOman, overmature in the foreland basin, whereas theShuaiba, which is only a lean source rock, is in theoptimum level of the oil window. To the west of theLekhwair high and in central UAE, Diyab source rocksare currently within the gas window, whereas excellentquality Shuaiba source rocks are in the oil window(Taher, 1997).

Figure 14. The genetic classi-fication of petroleum systemsconsists of applying three geo-logical factors: charge factor,migration drainage style, andentrapment style (Demaisonand Huizinga, 1994).

The Lekhwair high is the highest point on the pe-ripheral foreland bulge, and hydrocarbons generated inits surroundings charge several fields on this large struc-tural high (Figures 10, 12). The Shuaiba/Tuwaiq pe-troleum system has been classified as a normallycharged, laterally drained, low-impedance foreland pe-troleum system (Figure 14).

Natih Petroleum System of North OmanBurial and thermal modeling of the source rocks in themiddle Cretaceous (Cenomanian–Turonian) NatihFormation of the Wasia Group (Figure 3) indicates thatoil generation began during the Late Cretaceous andcontinues today (Figure 7). The interval is currently inthe oil window in most of the Oman foreland basinand has just entered the oil window in a shallow ex-tension along the Maradi fault zone (marked MFZ onFigure 12).

Modeling shows oil migration at the Natih For-mation level was initially directed toward the invertedGhaba salt basin and peripheral bulge of the basin;however, formation of the Fahud fault (marked FF onFigure 12), early in the development of the foreland


basin, created an extensive shadow zone and is themost likely reason Natih oils have not been foundacross the Fahud salt basin (Figure 11).

Gas generation from the predominantly oil-proneNatih source rocks is limited. Modeling indicates thisgas generation only commenced in the latest Tertiaryin the deepest part of the Oman foreland basin. This

Figure 15. (a) Paleo-Ara saltedge positions and charge tim-ing and (b) lithofacies of intra-salt sequence and oil typesfound in fields along the eastflank with oil types calculatedfrom biomarker compositionsusing cluster analysis.

deep thermal gas currently migrates to the Lekhwairhigh and Salakh arch. In the latter, the Natih For-mation is exposed. Thus the gas most probably es-capes to the surface. An alternative explanation is thatmost of the gas found in the Natih Formation mayinstead be derived from the deeply buried, highly ma-ture Early Cambrian Ara source rocks (Figure 11).

Terken et al. 1837

Like the Natih, this source rock is initially mainly oilprone (Terken, 1999). Consequently, the majority ofthe gas is expected to originate from thermal crackingof oil in deep traps.

The Natih petroleum system of north Oman isclassified as a supercharged, laterally drained, high-impedance foreland petroleum system (Figure 14).Despite the advance of the thrust front, charge mi-gration has remained mainly lateral because of de-tachment within the deeply buried Early CambrianAra salt sequence, which caused most of the com-pressional stress to be accommodated along wrenchfaults high on the gently northward dipping flankof the peripheral foreland bulge. Undisturbed mi-gration routes and large structural closures are re-garded as the main reasons for the high generation-trapping efficiency in this petroleum system(Terken, 1999).

Figure 16. Cross section across the south Oman salt basin showing the late Precambrian–Early Cambrian south Oman Huqfpetroleum system. Hydrocarbons generated by Precambrian Nafun and Early Cambrian Ara Group source rocks were released onlyafter the Ara salt dissolved and were trapped below younger seals in structures that resulted from halokinesis in the peripheral rimsyncline. No economic hydrocarbon accumulations have so far been discovered above the Ara salt basin proper. Thermal crackingof oil to condensate and gas is assumed to occur at temperatures in excess of 130�C. For stratigraphic legend see Figure 3; SR �source rock.

ENTRAPMENT STYLES AND TRAP TIMING

In north Oman, most structures are fault/dip or pop-up closures aided by salt-assisted footwall uplift. Manywere initiated in the Paleozoic and resulted from syn-depositional halokinesis and downbuilding (groundingof the overburden) near active fault zones. Youngerstructuration is the result of Late Cretaceous and Ter-tiary compression related to the foreland basin devel-opment and contemporaneous northward drift ofgreater India. During the first Alpine tectonic phase,obduction of the Semail Ophiolite and downbendingof the foreland in the Late Cretaceous and early Ter-tiary (Figure 1) led to normal faulting and formationof conjugate sets of transtensional strike-slip faults.During the second Alpine phase in the middle to lateTertiary, normal and strike-slip faults near the thrustfront were inverted, and more distant faults were


Tabl

e2.

Om

an’s

Petro

leum

Syst

ems

Rank

edby

Reco

vera

ble

Hydr

ocar

bons

inBi

llion

sof

Kilo

gram

s(1

09kg

)

Nam

e

Geog

raph

ical

Exte

nt(k

m2 )

Mat

ure

Sour

ceVo

lum

e(1

010m

3 )

Gene

rate

dHy

droc

arbo

ns(1

09kg

)O

ilin

Plac

e(1

09kg

)Ga

sin

Plac

e(1

09kg

)

Tota

lHy

droc

arbo

nsin

Plac

e(1

09kg

)

Gene

ratio

n/Ac

cum

ulat

ion

Ratio

(%)

Reco

vera

ble

Oil

(109

kg)

Reco

vera

ble

Gas

(109

kg)

Reco

vera

ble

Hydr

ocar

bons

(%)

Petro

leum

Syst

emRa

nkin

g

Huqf

Sout

h40

,000

300*

275,

000

3260

120

3380

1.4

520

800.

1La

rge

Huqf

Nor

th50

,000

180*

*14

0,00

010

0035

013

501.

033

023

00.

4La

rge

Dhah

aban

50,0

0036

29,0

0013

6044

018

006.

326

029

01.

8La

rge

Nat

ih20

,000

1012

,000

1100

–11

009.

021

0–

1.8

Sign

ifica

ntTu

wai

q10

,000

56,

000

6020

801.

317

130.

5Sm

all†

B5,

000

10††

2,00

030

3060

3.0

99

1.0

Very

smal

l

*Sou

rce

area

ism

atur

ebu

tsto

pped

gene

ratin

ghy

droc

arbo

nsm

ore

than

400

Ma.

**O

nly

Mes

ozoi

can

dCe

nozo

icso

urce

area

sin

the

Fahu

dsa

ltba

sin.

† Smal

lin

Om

an,b

uta

gian

tpet

role

umsy

stem

inth

eUn

ited

Arab

Emira

tes.

††N

umbe

rsas

sum

eth

atB

oili

sde

rived

from

aB

sour

cero

ckan

dis

nott

here

sult

ofth

erm

alcr

acki

ngof

Huqf

and

Qoi

ls.

reactivated and reversed both vertically and laterally(Loosveld et al., 1996).

In central Oman, most structures are located alongnortherly plunging structural highs that formed duringthe Late Cretaceous and Tertiary in response to reac-tivated north-south–trending basement faults. Trapsconsist mostly of fault/dip closures below the regionalKhuff (Permian) seal, but combined stratigraphicstructural traps are expected wherever east-west–trending Gharif channels cross north-south–trendingstructural noses (Terken and Frewin, 1999). Thesecould hold substantial undiscovered reserves.

Trapping in the south Oman salt basin is stronglycontrolled by the Early Cambrian Ara salt. In the coreof the basin, where the salt is still present, most of theoil generated in the Paleozoic is still trapped in intrasaltcarbonate and siliceous (silicilyte) stringers. In the pe-ripheral syncline along the east flank, salt dissolution isthe controlling parameter of structural style and trapformation (Heward, 1990), whereas retreat of the saltedge is the main factor for charge timing (Figure 15).Traps in Paleozoic clastics were initially formed byhalokinesis, and subsequently by salt dissolution. Thelatter process removed most of the salt along the eastflank of the south Oman salt basin, and thus it is largelyresponsible for the present-day structures. They mimica negative image of the structures formed during theearlier halokinesis stage wherever early withdrawal ba-sins became inverted into turtle structures. Anticlinesresulted from drape of strata over Haima and Al Khlataturtle structures and laterally discontinuous siliceousand carbonate stringers. Those became grounded rem-nants and now form chaotic solution residues.

REGIONAL PETROLEUM CHARGE RISKS INONSHORE OMAN

Basin modeling and petroleum system analysis explainwhy the areas with remaining significant petroleumcharge risks are restricted to the Fahud salt basin andforeland basin in northwestern Oman (Figure 17).They have also highlighted the importance of long-distance oil migration along regional arches, in placesup to 300 km away from the source kitchens (Figure13). Migration modeling shows that the petroleumcharge generated during the early and middle Paleozoicfrom late Precambrian and Early Cambrian Nafun andAra source rocks in the Ghaba salt basin in north Omanspread out across the flanks of this sag basin. Some ofthis early charge was biodegraded and turned into tar

Terken et al. 1839

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quent) seal breaching in the Tertiary is the most likelyreason for the escape of the hydrocarbons. Similar re-sidual Q-oil columns occur below oil and gas accu-mulations in Haima (Late Cambrian–Early Silurian)and Gharif (Permian) reservoirs along the westernmargin and in the core of the Ghaba salt basin. Manyof these discoveries of major dead oil residual columnsmay be only remnants in the culminations of oncesupergiant accumulations. In central Oman, several ofthese structures are deeply buried and have never beentested because of their gas risk, but with the explora-tion focus gradually shifting from oil to gas, substantialnew opportunities may emerge in this area.

Modeling and empirical data in south Oman haveshown that hydrocarbon generation from late Precam-brian to Early Cambrian Huqf source rocks predatesfinal entrapment by up to 400 m.y. Furthermore, theyhave highlighted the factor of Ara salt dissolution,which has been the result of hydrodynamic fluid-flowactivity. Salt dissolution has determined the structuralstyle and timing of trap formation, whereas retreat of

following middle Paleozoic erosion. High formationtemperatures since the Late Cretaceous, subsequently,turned the tar accumulation into pore-filling residualpyrobitumens (Huc et al., 2000). Reservoir quality inold, early-formed structures, therefore, can be ex-pected to be poor. Thus exploration should preferablytarget younger structures related to foreland basin de-velopment since the Late Cretaceous to reduce reser-voir quality risks (Figure 17a, c). Insufficient structur-ation, however, during the Mesozoic passive margindevelopment period may have caused much of the latePaleozoic–middle Cretaceous regional charge to dis-perse or escape (Figure 17b).

Restriction of the more recent Mesozoic to Terti-ary charging to the west flank in the Fahud salt basinof northwestern Oman has also increased the chargerisk for the Haima (Middle Cambrian–Early Silurian)sequence in the eastern half of the Ghaba salt basin.Eastward migrating hydrocarbons in the eastern halfare hindered by a pronounced syncline at depthsgreater than 3 km in this basin. So far, hydrocarbonson the eastern side of the Ghaba salt basin axis havebeen found only in the post-Haima (Permian and Me-sozoic) sequence (Figure 18). Favorable structural dipsand good seal integrity in the Permian Gharif and mid-dle Cretaceous Shuaiba formations permit lateral mi-gration of hydrocarbons. Seal integrity is only mini-mally interrupted by isolated piercing salt diapirs in thecore of the Ghaba salt basin (Figure 19).

An adverse timing exists between early Q-oil gen-eration during the Permian and Triassic in the south ofthe Fahud salt basin and trapping mechanisms in cen-tral Oman along migration paths that became activeonly during the Late Cretaceous and Tertiary (Figures7; 11; 17b, c). This suggests that the Q oil may havebeen initially stored in deep traps somewhere, beforebeing remobilized at shallower depth and in youngerreservoirs to its current trapped locations up to 300 kmaway from the generative kitchens (Figures 11, 13).Long-term storage of hydrocarbons from an evolvingkitchen would explain why there is relatively limitedinfluence of oil maturity on benzocarbazole ratio, al-lowing it to be used very effectively as a migration dis-tance indicator in this case.

Physical indications for breached or currently gas-charged closures that could have functioned as tem-porary oil reservoirs have been found in several places.For example in Hazar (Figure 17c), a long residual oilcolumn in Haima (Late Cambrian–Early Silurian) res-ervoirs indicates that once a large Q-oil accumulationexisted in this location. Gas charging and/or (subse-

Figure 18. Oil and gas charge risks for the post-Haima (LateCarboniferous–Tertiary) sequence.

Terken et al. 1841

the basin’s salt edge has controlled the timing of oilcharging in the traps (Figures 15, 17, 18, 19). Conse-quently, the risk for finding oil is low in the peripheralsyncline and in intrasalt reservoir stringers, but high inthe postsalt sequence above the salt basin proper.

Virtually all source rock systems in Oman had apredominant oil-prone character, at least initially.Consequently, a large part of the gas is thought to bethe by-product of thermal cracking of earlier trapped,liquid charges in reservoirs and source rocks. The riskfor oil and the probability for finding gas increases sig-nificantly in reservoirs hotter than 130�C, which is thetemperature generally interpreted to mark the onset ofthermal cracking of oil to gas with completion at 150–175�C (Hunt, 1996). Although relatively hot oil res-ervoirs are known (e.g., Price, 1982), these lower tem-peratures are modeled for the oils in Oman (Figures10, 11, 16). Given the amount of temperature data andthe number of 3-D models available, prediction of ar-eas at or above these threshold temperatures should bestraightforward.

This basin modeling effort has permitted us to mapthe areal extent and to genetically classify the differentpetroleum systems of Oman (Figure 14). Table 2 sum-marizes the total quantity of hydrocarbons expected tohave been generated in onshore Oman by the differentsource rocks, the discovered amounts of oil in place,the actually recoverable petroleum volumes, and thegeneration-trapping efficiencies of the different petro-leum systems. The high-impedance Natih (middleCretaceous, Cenomanian–Turonian) petroleum sys-tem in the foreland basin appears to be the most effi-cient system for oil retention in Oman, whereas theinitially prolific Huqf systems of late Precambrian–Early Cambrian age, are the least efficient because onlya small percentage of the oil volumes initially generatedhave been preserved.

CONCLUSIONS

Modeling and measured empirical data together pro-vide an understanding of the petroleum charge risks inOman. Areas of Mesozoic and Cenozoic charge are re-stricted to northwestern north Oman, the only areawhere rather prolific late Precambrian–Early Cambrianand Mesozoic source rocks are currently at their max-imum temperature levels.

Large parts of north and central Oman depend onlong-distance lateral migration from the Huqf and Qkitchens for their charge. We can demonstrate, bothgeologically and geochemically, that favorable condi-tions in central Oman have permitted lateral migrationto transport oil some 300 km away from its source area.

The south Oman salt basin depends solely on EarlyCambrian–Ordovician charge, which is released instages from traps below the Ara salt sequence and instringers encased in the Ara salt. This occurred whenthe salt edge retreated because of salt dissolutioncaused by hydrodynamic fluid-flow activity.

Source rocks in Oman are multiple, generally rich,and fairly widespread marine sequences. They are pre-dominantly oil prone, and most of the gas found is in-terpreted to result from thermal cracking of liquid hy-drocarbons trapped in deep reservoirs and retained insource rocks. The chance of finding gas increases sig-nificantly in reservoirs hotter than 130�C, which is aboundary generally observed to mark the onset of oilcracking to gas.

This petroleum review, combining geology, geo-physics, and geochemistry, has revitalized some of themature plays such as the Gharif Formation play, where

Figure 19. Oil and gas charge risks for the pre-Haushi (EarlyCambrian–middle Paleozoic) sequence.


oil exploration is now refocused along Late Cretaceousand Tertiary migration paths existing on regionalarches. Furthermore, deeper stratigraphic targets areenvisaged to offer economically significant potential formajor gas reserves. The deep Haima (MiddleCambrian–Early Silurian) gas play in north and centralOman can now be usefully subdivided into a low-riskwestern and a higher-risk eastern sector, a useful as-sessment capable of guiding the deployment of explo-ration funds.

Modeling has also outlined the extent and deter-mined the styles and efficiencies of the different petro-leum systems of Oman. The generation-trapping effi-ciency is clearly highest in the high-impedanceforeland basin Natih (middle Cretaceous, Cenoman-ian–Turonian) petroleum system of northern Oman.

APPENDIX : TECHNICAL ANNEX

Modeling Input Parameters

The 3-D in-house geohistory modeling package used to model thehydrocarbon generation history has been designed to solve the 3-Dheat-diffusion equation (Giles et al., 1999). The program uses asinput the mantle heat-flow history, the heat capacity and thermalconductivity for the various lithologies, the surface temperature his-tory, and the burial history. Calculations are iterated by adjustmentof the crustal radiation constant, until the calculated present-daytemperature field fits the observed thermal structure constructedfrom well-log temperature measurements. Modeled maturities andpaleotemperatures are iterated against the vitrinite reflectance esti-mates from source rocks and FT data for best fit. Full decompactionis applied in the reconstruction. Migration modeling was carried out

Figure 20. Heat-flow and surface-temperature histories used for the modeling.

using a simple updip migration algorithm (Hermans et al., 1992) thattakes pressure, volume, and temperature effects into account in pre-dicting oil vs. gas. Decompacted burial history maps and predictedporosity maps were generated during thermal modeling and werealso part of the modeling input.

Heat-Flow History

The paleo–heat-flow history used in the modeling reflects Oman’sstructural evolution (Figure 20). This is approximately subdividedinto three phases of evolution: intracratonic rifting in the earlyPaleozoic–middle Paleozoic, passive margin development from thelate Paleozoic to the middle Mesozoic, and active margin tectonicssince the Late Cretaceous (Loosveld et al., 1996).

Highest heat flows are postulated to have occurred in theearly Paleozoic in the Ghaba salt basin to the north and the southOman salt basin (Figures 1, 20). Although both areas are thoughtto have experienced slightly different tectonic histories during thefinal stage of the early and middle Paleozoic extensional event(Loosveld et al., 1996), similar heat-flow histories were used.

Another heat pulse of lesser magnitude, related to regionaluplift, is assumed to have occurred during the late Paleozoic, butit affected mainly eastern Oman. Tectonic quiescence and normalto low heat flows mark the late Paleozoic–middle Mesozoic, aperiod of continental drift and margin subsidence. Since the LateCretaceous, the thermal flux history has clearly been influencedby the hydrodynamic fluid-flow activity associated with the riseof the Oman Mountains in the north and the Dhofar Mountainsin the south (Lamki and Terken, 1996). Currently, high subsur-face temperatures, which result from rising hydrodynamic dis-charge and hot formation waters squeezed from intervals beingburied below the advancing thrust belt in the Oman Mountains,mark the foreland basin (K. Juhasz-Bodnar et al., 1999, unpub-lished data) and also extend into central Oman (Terken and Fre-win, 1999). Low subsurface temperatures outline areas with hy-drodynamic recharge by cool meteoric water in large parts ofsouth Oman and along the east flank in north Oman. It has tobe realized that the extent of the recharge areas still reflects much

Terken et al. 1843

Figure 21. Map showingthermal provinces in Oman. Ap-atite fission track (AFT) data in-dicate that the only area atnear maximum temperature to-day is western Oman.

wetter conditions during the last Quaternary glacial period (Lamkiand Terken, 1996). As a result of these thermal history recon-structions, 14 heat-flow history maps were used to model thethermal flux history.

Surface Temperature History

The paleosurface (or water-sediment) interface temperatures wereestimated from the paleolatitudes of Oman (Lamki and Terken,1996) and the depositional environment. The curve (Figure 20)shows mainly long warm periods marked by deposition of evaporites,red beds, and carbonates interrupted only by shorter cold spells re-lated to glacial events during the Vendian, Ordovician, and LateCarboniferous–Devonian, the latter being suggested by the presenceof diamictites.

Burial and Thermal Histories

The Oman stratigraphic rock sequence shows large hiatuses, mainlydue to erosion related to the progressive tilting of the east flank andassociated basin contraction (Figure 3). Seismic data show no pro-nounced thinning of the individual units within the postrift Haima(Late Cambrian–Early Silurian) Group, but the unconformity at thebase of the overlying Haushi (Permian) Group cuts into increasinglyolder formations toward the east and indicates differential uplift oc-curred during the Carboniferous. The Mesozoic formations clearlydisplay an easterly thinning wedge and show that the missing over-burden at unconformities during this period is less than that betweenthe Permian Haushi and Late Cambrian–Early Silurian Haimagroups. The base Tertiary unconformity displays again clear under-lying truncations.


Missing overburdens at these unconformities have been quan-tified from seismic data, compaction trends from sonic velocity logs,FT analyses, and maturities estimates (vitrinite reflectance estimates)derived from coals (desmocollinite), solid hydrocarbons, and oils(biomarker ratios, Tmax). The FT data indicate that a large part ofOman experienced maximum temperatures during the Paleozoic(Figure 21). Areas currently at maximum burial temperature are re-stricted to the Fahud salt basin, the foreland basin in northwesternnorth Oman, and the Rub’ Al-Khali basin in western south Oman(Visser, 1991; Indrelid and Terken, 2000). Significant erosion ofsome 2500 m along the east flank and up to 800 m in the west isestimated to have occurred prior to Haushi (Permian) Group dep-osition, whereas a similar tilting during the Late Triassic may haveremoved some 600 m of Triassic–Permian Akhdar Group sedimentsin the east. Uplift along the east flank of the basin in the Tertiarymay amount to 1000 m; however, the contribution by hydrodynamicfluid-flow activity to the observed cooling of the east flank is difficultto quantify.

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petroleum systems of oman, charge timing and risks

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