The Cretaceous Natih petroleum system is one of the smaller petroleum systems in Oman, measuring only some 20,000 square kilometers in areal extent. Resource volumes of oil initially in-place, however, are significant and amount to 1.3x109 cubic meters (equivalent to 8.2 billion barrels). Most of the recoverable oil is concentrated in two giant fields that were discovered in the early 1960s. Since that prolific time no new major discoveries have been made, except some marginally economic accumulations in the early 1980s.

To evaluate the remaining hydrocarbon potential of the system, the oil kitchen was mapped and its generation and migration histories modeled and integrated with the regional setting to outline the geographical and stratigraphical extent of the petroleum system. The volume of liquid hydrocarbons generated by Natih source rocks was calculated and compared to the estimated oil-in-place to determine the generation-trapping efficiency of the petroleum system. Some 100x109 cubic meters of source rock is currently mature and produced a cumulative volume of 14x109 cubic meters (88 billion barrels) oil. Of this volume 9% has actually been discovered and 0.25x109 cubic meters (1.57 billion barrels) are currently booked as recoverable reserves, equivalent to 1.8% of the total generated volume. Both percentages classify the Natih petroleum system as the most efficient system in Oman.

This extreme efficiency results from several factors, such as: (1) modest structural deformation in the foreland basin, which permits lateral migration to remain the dominant style; (2) abundant and uninterrupted access to oil charge from an active kitchen in the foreland basin; and (3) excellent intra-formational source rocks, which is retained by thick Fiqa shales. Most structural prospects have been tested in four decades of exploration. The remaining hydrocarbon potential is anticipated to exist mainly in stratigraphic traps in Fiqa turbidites in the foreland basin, and truncation traps across the northern flank of the peripheral bulge.


After almost four decades of intense exploration, many of the traditional plays in the Petroleum Development Oman (PDO) acreage are strongly creamed and the search is on for other less obvious plays and subtler trap styles. In North Oman this has led to renewed interest in the Upper Cretaceous/Tertiary foreland basin (Figure 1), where new objectives are recognized in stratigraphic traps in Fiqa turbidites and truncation traps below onlapping Fiqa shales across the peripheral bulge (Figure 2). Most prospects in these plays, however, are located beyond the active Natih oil kitchen area and access to oil charge is considered a serious risk. To determine this risk and the remaining potential, the Natih petroleum system was mapped and the generation and migration histories of both Natih and deeper Precambrian/Cambrian Ara salt source rocks was modeled and integrated with the regional setting.

Natih-sourced oils occur in a small area, less than 20,000 square kilometers (sq km) (Figure 1). Significant reserves of around 1.3 billion cubic meters (m3) in STOIIP (stock tank oil originally in-place) have been found in half a dozen oil fields. Most of the oil lies in two giant fields, Fahud and Natih, which hold 145 million m3 (910 million barrels) and 100 million m3 (628 million barrels) reserves respectively, of 32° API oil. Both fields were discovered in the early 1960s during exploration which targeted large anticlines with surface expression. Smaller marginal economic discoveries were made in the late 1970s and early 1980s in the complex Maradi Fault Zone. Subtle traps were hardly targeted and truncation traps were only tested twice, unsuccessfully, along the crest of the peripheral foreland bulge. Stratigraphic traps and combined fault-dip/truncation closures along the gentle flank of the foreland basin were regarded as high risk and have remained largely unexplored.


Our knowledge of the main elements of the Natih petroleum system is extensive, but has never been completely integrated. Type, quality and distribution of oils and source rocks are well-defined and supported by continuing geochemical research by techniques which were described by Lijmbach et al. (1983). Time/depth constraints for the burial and thermal history modeling are provided by apatite fission track (AFT) data in some 20 wells and by petrographic studies (Juhasz-Bodnar et al., 1999; in press). The current hydrodynamic fluid-flow activity in the foreland basin is outlined by 50 reservoir salinities and 1,500 borehole formation temperatures (Al-Lamki and Terken, 1996).

The regional structural setting in North Oman is also well-understood from some 200 exploration wells, extensive 2-D (115,000 km) and 3-D (33,000 sq km) seismic data and decades of fieldwork by geologists, attracted to the region by the world famous ophiolite outcrops and impressive scenery of the Oman Mountains. All this information was combined in this basin modeling study to reconstruct the generation and migration histories for the Precambrian/Cambrian Ara and Cretaceous Natih source rocks and determine the remaining hydrocarbon potential of the Natih petroleum system.

The modeling was carried out with Shell’s proprietary 3-D basin modeling package IBS (Giles et al., 1998). Regional maps of 11 stratigraphic levels, that extend up to the deformation front of the Oman Mountains, were used together with 3 constructed horizon maps that represent maximum burial levels prior to major Tertiary erosional events (Figure 2). Ara salt movement and heatflow history maps were constructed for all horizon maps. The present-day thermal field was used as a guide to model the thermal flux history since the Late Cretaceous in the foreland basin (Al-Lamki and Terken, 1996); while the Early Paleozoic history was based on a rift setting in the Ghaba Salt Basin (Figure 1).


Oman lies on the eastern margin of the Arabian Platform and became the site of carbonate platform deposition from the Early Jurassic to Late Cretaceous following the break-up of Gondwana and opening of the Neo-Tethys Ocean (Hughes-Clark, 1988; Le Métour et al., 1995). The Natih Formation of latest Albian to early Turonian age (Figure 2), represents the youngest prograding carbonate sequence of this succession (Van Buchem et al., 1996). Local erosion and karstification of its top indicate that uplift and emergence ended its deposition.

This uplift signals the onset of the first Alpine tectonic event during which the opening of the Atlantic Ocean led to closure of the Neo-Tethys Ocean (Bechennec et al., 1995; Loosveld et al., 1996). In North Oman, the shift to a compressive setting resulted in obduction of oceanic crust and development of a foreland basin bounded by a peripheral bulge in the south (Figures 1 and 3). The culmination of this positive feature was in the Lekhwair/Dhulaima area, where extensive erosion removed most of the Natih. In other parts of the basin, a hiatus of 2 to 3 million years separates the Natih from the overlying Aruma foreland basin fill. The late expansion of this infill towards the peripheral bulge in the earliest Campanian illustrates the initial under-filled character of the foreland basin (Boote et al., 1990; Warburton et al., 1990).

Obduction of the ophiolite allochthon in the early Campanian was followed in the late Campanian and early Maastrichtian by thrust stacking and resulted in the shedding of large amounts of shaly sediments into a now rapidly subsiding foreland basin (Figure 3). Loading of the thrust sheets resulted in further down-warping of the continental crust and its flexural extension (Bechennec et al., 1995; Loosveld et al., 1996). The northward drift of greater India, at the time, added a component of compression along the eastern margin of Oman (Peters et al., 1995). The combined effect of these two plate margin processes was the initiation and/or reactivation of a conjugate set of north northeast-south southeast and northwest-southeast strike-slip faults in North Oman.

Deformation stopped abruptly during the Late Cretaceous when a new subduction zone developed in offshore Iran (Le Métour et al., 1995). Stable conditions characterized the Early Cenozoic. Foreland basin sedimentation resumed when continent-continent collision occurred along the Zagros Suture in the Oligocene. During this second Alpine tectonic event, folding and uplift in the Oman Mountains led to shortening and local inversion in the foreland, with major reverse movement along some of the normal and strike-slip faults (Loosveld et al., 1996).


The Natih Formation consists of a 400-meter (m) thick carbonate succession, which in the subsurface has been subdivided into seven litho-stratigraphic units: A to G (Figure 4). A recent study of its stratigraphic architecture in outcrops of the Salakh Arch (Van Buchem et al., 1996; Figure 1) shows the formation to comprise three major (A/B, C/D and E units) and two minor (F and G units) depositional sequences. The former have been linked to 3rd-order eustatic sea-level changes.

Two of the major sequences, the upper A/B unit and lower E unit, are very similar, however the middle one, comprising of the C/D unit, is significantly more clay-rich and lacks the facies variation of the others. The A/B and E units are characterized by bioclastic grainstones in the progradational upper part and organic-rich shaly limestones and clayey marls in the transgressive lower interval of the cycle.

The hardground found on top of the Natih E unit, the main seismic marker of the interval, was interpreted to correspond to the mid-Cenomanian sea-level drop, while the transgressive B unit was linked to the late Cenomanian/Turonian sea-level rise.


Source Rock

Two source rock intervals are found in outcrops in the Natih B and E units and have also been identified on well logs (Figure 4). The Natih B source rock is up to 50 m thick and excellent in quality; the Natih E is thinner and mostly mediocre in quality. Both intervals contain Type I/II source rocks. Total organic carbon content (TOC) in the Natih B range up to 15%, but average 5%, while the TOC in the Natih E rarely exceeds 5% (Figure 5). The organic matter is predominantly structureless and mostly load-bearing. Impregnations in lean beds in the top of the analyzed interval in well Maradi Ladah-2 indicate that generation commenced at very shallow depths and is supported by actually measured activation energies in the range of 190 to 208 Kilo calorie (Kcal)/mole.

Pyrolysis sniff analyses were carried out in 1991 on some 200 PDO and non-PDO wells in adjacent blocks that penetrated the Natih Formation. The source rock was found to be restricted to North and Central Oman (Figure 6) and bounded by a platform carbonate rim facies (Van Buchem et al., 1996). Source rock deposition occurred in an intra-cratonic basin on the Arabian Craton, that was connected to the open (Neo-Tethys) ocean in the northwest (Murris, 1980). Maximum burial of the source rock is in the foreland basin, where the Natih E interval is currently at a depth of some 3,000 m.

Oil/Oil and Source Rock/Oil Correlations

Natih oil is differentiated geochemically from the other oil types in Oman. The distinct dominance by one of the steranes, so characteristic for the Precambrian/Cambrian Huqf (C29) and Q (C27) oils (Grantham et al., 1987; Terken, 1998), is absent in this oil (Figure 7). Moreover, a cross-plot of the C27 sterane percentage (related to C27 + C28 + C29 steranes) versus total oil carbon isotope value (Figure 8) separates the Natih oil not only from the Huqf and Q oils, but also from the (Mesozoic) Tuwaiq oil with a very similar total oil carbon isotope value (Ruwehy and Frewin, 1998).

These parameters also permit an easy mapping of the geographical extent of the Natih petroleum system and show Natih oil to be restricted to a small area in central North Oman (Figure 9). This distribution is structurally controlled, to the south by the peripheral bulge, and in the east by the deformed core of the Ghaba Salt Basin (Figure 10).

Natih oil has been discovered in eleven locations, six of which are regarded as economic accumulations (Table 1). The Shibkah field yields the purest variety of Natih oil and is considered to represent the end-member of this oil type. Mixing experiments by Shell Research with other oil types in North Oman indicate mixing to occur along linear lines between end-members and permits contributions from the different oils in mixtures to be estimated (Figure 11). Oil in the giant Natih field was determined to comprise of three-fourths Natih and the remainder of an equal mixture of Huqf and Q oils. In the other giant field, Fahud, Natih oil only contributes about half, while again the remainder is split equally between Huqf and Q oil.

Total (m3x106) 1,265 245

Total 10 barrels x 106 7,944 1,538

STOIIP = Stock tank oil originally in-place

UR = Ultimate recoverable oil volume

NI = Nickle in parts per million

Va = Vanadium in parts per million

S = Sulphur content in weight percentage

Pr/Ph = Pristane/Phytane ratio

C7VRE = Vitrinite Reflectance Estimate from C7

B-VRE = Vitrinite Reflectance Estimate from biomarkers

C27% = percentage C27 Steranes related to C27 + C28 + C29

Top Res. (m) = Top Reservoir in meters

Extract analyses have been carried out on all Natih reservoirs with hydrocarbon shows and mature Natih source rock intervals. Good matches between these extracts and Natih oil were found in most cases (Figure 7).

Reservoirs and Seals

Nearly all Natih oil is retained within the Natih Formation itself. Detailed studies of this carbonate reservoir in the giant Natih and Fahud fields show the A, C/D and E units constitute the three main hydrocarbon-bearing reservoirs (Figure 4). All three are dual porosity/permeability systems of mostly low permeability rock matrix dissected by locally dense fractures (Whyte, 1995). Porosity, which is both primary and fracture-related, is often high, up to 40% in Fahud and 30% in Natih, and enhanced by fresh water leaching. Deep-marine shales of the Fiqa Formation onlap the top of the Natih Formation and provide an excellent seal in most parts of North Oman.

Occasionally Natih oil also occurs in the older Shu’aiba Formation (Figure 2). However, only in reverse fault/dip closures with large throws, e.g. Natih and Fahud, where this reservoir is juxtaposed against mature Natih source rock, which functions as source and lateral seal (Figure 3). The Shu’aiba carbonates exhibit a greater lithofacies variation than the Natih, and are locally karstified. The interval has been interpreted as a northwestward prograding, shallow carbonate margin sequence, that was exposed across salt-induced highs prior to transgression by Nahr Umr marine shales, the best regional seal in Oman.

The next exploration phase will target turbiditic sands in the Fiqa Formation (Figure 2). These sands, that have so far only been penetrated to the east of the Maradi Fault Zone, originated from the rising Oman Mountains and filled the foreland basin in an axial direction from the east (Figure 3). In a proximal setting they are texturally immature, but reservoir quality is expected to improve westward with greater distance from their provenance. Future exploration wells will appraise this play near the active Natih oil kitchen, but only in locations where faults have breached the lower Fiqa seat seal and provided access to charge.


Most structures in North Oman are related to the foreland basin development and contemporaneous northward drift of greater India. Obduction and downbending during the first Alpine tectonic phase (Figure 2) led to normal faulting and formation of a conjugate set of transtensional strike-slip faults (Figure 1). During the second Alpine phase normal and strike-slip faults near the thrust front, such as the Natih Fault and northern section of the Maradi Fault Zone, were inverted. While more distant strike-slip faults, like the Fahud Fault, were reactivated transpressionally and reversed both vertically and laterally (Loosveld et al., 1996). Most structures are aided by salt-assisted footwall uplift and can be classified as simple fault-dip or pop-up closures (Table 1).


Burial and thermal modeling of the Natih source rocks indicates oil generation started at the end of Fiqa deposition during the Late Cretaceous and continues today (Figures 12, 13 and 14). Source rock conversion has reached 90% in the deepest part of the kitchen in the foreland basin and about 40% in a shallow extension along the Maradi Fault Zone to the east of the Natih and Fahud fields (Figure 15).

Modeling shows oil migration was initially directed towards the inverted Ghaba Salt Basin and peripheral bulge. However, formation of the Fahud Fault early in the development of the foreland basin, created an extensive shadow zone and is the most likely reason Natih oil is absent from large areas to the south (Figures 14, 15 and 16). The Natih Fault, which developed since the Middle Tertiary, subsequently captured the oil charge to the Fahud field (Figure 17). Natih oil in Fahud, therefore, is Early Tertiary in age and most probably migrated some 40 to 50 km from the only mature kitchen area in the foreland basin (Figure 14). In contrast, the younger Natih structure is still connected to the active and more mature kitchen by shorter migration routes of some 20 km. Paths to this field were initially longer (30 km), but shortened over time as the foreland basin prograded and kitchen area expanded southward (Figure 15).

Oil maturity estimates (expressed as VRE - vitrinite reflectance estimate) derived from biomarkers are lower in Fahud than in the Natih field, 0.73 versus 0.88 (Table 1) and confirm the model. The difference in maturity is caused by the Natih oil contribution, which in Fahud was largely derived from just-mature source rocks and mixed with highly mature Huqf and Q oils generated by deeply-buried Ara source rocks (Visser, 1991). The higher oil maturity in the Natih field reflects the more mature nature of younger Natih oil charge.

Gas generation by the predominantly oil-prone Natih source rocks is limited. Modeling indicates that gas generation only commenced in the latest Tertiary in the deepest part of the foreland basin. This gas currently migrates to the Dhulaima/Lekhwair area (Figure 1) and reaches the surface in the Salakh Arch, where the Natih Formation is exposed (Figure 15). Gas in the Natih Formation in the Yibal field is interpreted to be derived from deeper sources along the foreland bulge. Although the highly mature Ara interval is its most likely origin, these source rocks are, like the Natih, mainly oil-prone and only limited gas producers (Terken, 1998). On the peripheral bulge most of the gas in the Natih Formation is therefore expected to originate from thermal oil cracking in deep traps. Some of the gas may have been liberated from trapped oil following uplift, as a consequence of the reduction in reservoir pressure.


The mixing experiments have shown Natih oil has mixed with significant amounts of Huqf and Q oils in the Fahud and Natih fields (Figures 10 and 11). Access to charge from deeper Precambrian and Cambrian Ara salt-related source rocks has been linked to reactivated basement or extensional deep-seated faults in the down-warped and detached overburden, that breached the regional Nahr Umr seat seal (Figures 16 and 17). The faults provided vertical conduits for liquid hydrocarbons generated by Ara salt source rocks or re-migrating from breached or gas-charged Haima and Gharif traps (Terken, 1998).

Generation modeling shows that in the foreland basin these deeper source rocks were largely already overmature for oil during the Early Tertiary, prior to the formation of the Natih structure (Figure 18). But higher on the gentle flank of the foreland basin, where Fahud is located, these source rocks continued to generate liquid hydrocarbons into the Middle Tertiary (Figure 19). Consequently, the smaller contributions of Huqf and Q oils in the Natih field are explained by a less favorable timing between structuration and generation.


The quantity of hydrocarbons generated by the Natih source rocks was calculated and compared to the estimated oil-in-place to determine the generation-trapping efficiency of the petroleum system. The source rock was assumed to be 50 m thick on average and present only in western North Oman. An average TOC content of 5% by weight and initial hydrogen index (HI) of 600 mg HC/g TOC was used, together with the measured activation energies in the range of 190 to 208 Kcal/mole. The thermal flux varied from 40 milli Watt/m2 in stable, tectonically non-affected areas to 65-70 milli Watt/m2 in the Early Paleozoic rift in the Ghaba Salt Basin and Late Cretaceous foreland basin.

The source rock volume currently mature and generating oil was modeled to be some 10x1010 m3 and suggests the cumulative amount of generated hydrocarbons to be around 12x1012 kg, equivalent to 14x109 m3 (approximately 88 billion barrels) of 32° API oil. As the oil-in-place amounts to some 1.3x109 m3 (8.2 billion barrels), 9% of all generated hydrocarbons has actually been discovered. Of this volume 0.25x109 m3 (1.57 billion barrels) are currently booked as recoverable reserves, which equals to 1.8% of the total generated volume. These numbers classify the Natih petroleum system as an effective petroleum system (Magoon and Valin, 1994) and by far the most efficient in Oman.

Based on charge volume, migration drainage and entrapment style, the Natih petroleum system can be classified as an efficient but typical, normally charged, laterally drained, modest to high impedance foreland system (Demaison and Huizinga, 1994).


Several factors may explain the extreme efficiency of the Natih petroleum system. One of them is the rather modest structural deformation in the foreland basin, which is dampened by detachment of the overburden within the deeply-buried Ara salt sequence. Detachment permitted some of the compressional stress to be accommodated along wrench faults high on the gentle flank of the foreland basin, which left the core of the basin largely unaffected and resulted in the formation of some large structural closures. As a result the charge migration remained predominantly lateral and efficient, also helped by the presence of a good carrier bed with limited secondary migration losses. Another important factor is the presence of very thick Fiqa shales, which retained most of the oil, even after the structural relief increased significantly as a result of the advancing deformation front. This excellent seal may also have protected the oil from biodegradation by percolating meteoric water in the Fahud and Natih fields, where most of the oil is trapped in reverse fault-dip structures very close to the surface (Figure 3). The faults prevent water washing of the oil from meteoric water beneath the fields. Further access to charge from a still active kitchen with excellent intra-formational source rocks is regarded as another major contributing factor.

The periods when deposition of essential elements, onset of generation and important structural processes took place are summarized in the events chart (Figure 20); while the areal extent of the Natih petroleum system and areas of remaining hydrocarbon potential are shown in Figure 21. The structurally-bounded nature of the petroleum system limits the prospective area. Exploration scope is recognized in Fiqa turbidites in the vicinity of the mature Natih kitchen and in the Natih Formation, in complex structural settings in the Maradi Fault Zone. Further modest underexplored potential may exist in faulted truncation traps in the Natih Formation along the northeast flank of the Lekhwair/Dhulaima High and in fault/dip closures and truncation traps along migration paths on the western flank of the inverted Ghaba Salt Basin.


The Natih petroleum system is one of the smaller petroleum systems in Oman, but contains in proportion to larger ones, significant recoverable reserves. It is by far the most efficient petroleum system in Oman.

This extreme efficiency results from several factors such as modest structural deformation in the foreland basin, dampened by detachment from deep structuration by the Ara Salt. Detachment allowed large structures to form high on the gentle flank of the foreland basin and lateral migration to remain the dominant style. The uninterrupted access to an active kitchen in the foreland basin with excellent intra-formational source rocks provided abundant charge, which was retained by thick Fiqa Shales.

Basin modeling has revealed the structurally-bounded areal extent of the Natih petroleum system and outlined areas of remaining hydrocarbon potential. Exploration scope is recognized in Fiqa turbidites in the foreland basin and truncation traps in the Natih Formation across the peripheral bulge and along migration paths on the western flank of the inverted Ghaba Salt Basin.


The author wishes to thank the Ministry of Petroleum and Minerals of the Sultanate of Oman for permission to publish this paper. The author acknowledges the contributions of various PDO scientists, notably Ramon Loosveld, Peter Nederlof, Neil Frewin, Mike Naylor and Pascal Richard. He also wishes to thank the Shell RTS Geochemical Laboratory scientists for the analysis of numerous Omani oils and source rocks throughout the last 30 years. The author also thanks Gulf PetroLink for their assistance in redrafting the graphical displays.


Jos M.J. Terken ·joined Shell in 1982 and has worked in The Netherlands, Brunei, New Zealand and Indonesia. In 1993 he joined Petroleum Development Oman as a Senior Review Geologist/Basin Modeler in the Regional Studies Team, where he modeled and mapped the Huqf, Q, Natih and Tuwaiq petroleum systems. He is currently part of the Frontier Exploration Commercialisation Team and involved with reserve bookings from past and recent discoveries. Jos received a MSc (cum laude) in Geology and Sedimentology from the University of Utrecht in 1982.