The Sahmah Formation (Safiq Group, Haima Supergroup) of Oman is divided into a lower ‘Shale Member’ (or ‘Sahmah Shale’), and an upper ‘Sandy Member’. The Shale Member was deposited in a deep-marine environment, and the Sandy Member in a marginal marine setting. The formation is greater than 500 meters thick in the Burkanah-1 exploration well, located in south Oman along the eastern edge of the Rub’ Al-Khali Basin. In many areas in Oman, the formation is absent due to erosion by the ‘Hercynian’ unconformity. The age of the Sahmah is generally interpreted as Early Silurian Llandovery; however, recent biostratigraphic studies suggest that it may range in age from latest Ordovician Ashgill to Llandovery. The basal Sahmah Shale (3–10 meters thick) is an excellent source rock, as confirmed by its correlation to the ‘B’ oil in the overlying Permian Gharif Formation in the Sahmah field in central Interior Oman.

This study combined new and previously acquired geological data from 16 wells in Oman, and includes source rock analytical data. A basin model was used to assess the maturation history of the Sahmah Shale, and the hydrocarbon potential of two associated petroleum systems. The first system occurs along the ‘Hercynian’ erosional edge of the Sahmah source rock. The migration pathway involves vertical charging of the overlying Upper Carboniferous-Lower Permian Al Khlata Formation or/and the Permian Gharif Formation. This area constitutes the Sahmah Shale:Gharif Formation(!) Petroleum System. The second Petroleum System, the Sahmah Shale:Hasirah Formation(?), applies to regions where the Sahmah is thick, and intra-Sahmah shales act as a seal. In these regions, if the shale is mature and the pre-Sahmah section is porous, then down charging provides the migration pathway to the trap.


South and Central Oman are situated in an area with two petroleum systems (Figures 2 and 3, Table 2): (1) Precambrian:Gharif and additional reservoirs(!); and (2) Sahmah Shale:Gharif(!). [Note: petroleum systems are denoted by the source rock, a colon, reservoir(s), followed by an exclamation mark (likely) or question mark (unlikely or unproven)].

Most of the petroleum systems of Oman have been described in detail (e.g. Milner, 1998; Terken, 1999; Terken et al., 2001; Table 2), except for the Sahmah Shale:Gharif(!) and a new and a more speculative Sahmah Shale:Hasirah(?) petroleum systems. The purpose of this paper is to:

  • (1) describe the Sahmah Shale Member of the Sahmah Formation;

  • (2) appraise the petroleum systems of the Sahmah Shale source rock; and

  • (3) map the distribution of the petroleum systems of the Sahmah source rocks in south and central Interior Oman.

This study (Table 1) includes data acquired by Maersk Oil since 1996 (Burkanah-1 and Al Darmaa-1) when Maersk Oil joined Phillips Petroleum (now ConocoPhillips) in exploration of Blocks 36 and 38 in South Oman; and data from wells provided by the Ministry of Oil and Gas of Oman, Petroleum Development of Oman (PDO), and Petrogas (the license holder of Block 7 in Oman). The 16 wells (see Table 1) were drilled by different operators starting in the 1970s, and therefore the data quality varies considerably. The most recent and consistent data set is from the Burkanah-1 and Al Darmaa-1 wells.


The study area is situated in Oman, at the eastern edge of the Rub’ Al-Khali Basin and the western edge of the Oman Salt Basins (Figures 1 and 3). This region is occasionally referred to as the Su’aydan Platform. The Rub’ Al-Khali Basin is located in southern Saudi Arabia, south and central Interior Oman, and the United Arab Emirates. The basin contains sediments ranging in age from late Proterozoic to Recent (Figure 2).

The Phanerozoic tectonic history of the study area involved extended periods of subsidence that were interrupted by episodes of uplift and erosion (Figures 4-6) (Loosveld et al., 1996). A pronounced episode (or episodes) occurred during the late Paleozoic, and is represented by the ‘Hercynian’ unconformity. Another episode occurred during the Jurassic and Tertiary times, and affected the Dhofar area of south Oman. During the Carboniferous through Cretaceous time, the northern part of the study area was a stable platform, whereas the southern Dhofar area was uplifted and eroded. The Cretaceous obduction along the Oman Mountains had little effect on the area of investigation, apart from the generation of low relief anticlines.


Members of the Sahmah Formation

The Sahmah Formation (Safiq Group, Haima Supergroup; Droste, 1997) is divided into a lower ‘Shale Member’ (also named the ‘Sahmah Shale’), and an upper ‘Sandy Member’. The Shale Member consists of gray to brown organic-rich shale, and has a relatively smooth GR profile that increases with depth (Figure 7). The base is often marked with a significant GR spike associated with the highest organic content. The palynological assemblage indicates an inner marine environment. Robertson Research (Report, 2001) interpreted a maximum flooding surface at the base of the Shale Member.

The upper Sandy Member of the Sahmah Formation consists of intercalated sandstone and shale beds, 5 to 10 m thick, and exhibits a characteristic serrate GR log profile (Figure 7). The sandstone is gray, fine- to medium-grained, micaceous and pyritic, and the shale is gray or brown. Palynomorphs recovered from this member are mostly terrigenous and often associated with a marginal marine setting (Robertson Research Report, 2001).

Distribution of the Sahmah Formation

The Sahmah Formation is present along the western edge of the Rub’ Al-Khali Basin and extends into eastern Saudi Arabia (Figures 7 and 8). It may also be present in the Ghaba Basin of Interior Oman (Oterdoom et al., 1999, Figure 3); however information on this outlier is limited. Accordingly, the Sahmah Shale may have a wider regional distribution in Oman than indicated here. In the area around Burkanah-1, the Sahmah Formation is greater than 500 m in thickness (Figure 9). To the south and east, the formation is thinner due to erosion. Both Sahmah members are present in the Burkanah-1 well, but in several of the wells to the north only the Shale Member is preserved.

The isopach map of the Shale Member (Figure 10) shows that the thickest shale development occurs in Block 36 around Burkanah-1. To the north, the isopach map exhibits some rapid variations. For example, in the Ramlat-1 well (Figure 10), the entire Sahmah Formation is missing, whereas all the surrounding wells encountered the Sahmah Shale. The areas where the Sahmah thickness varies rapidly are interpreted as the result of incision of the ‘Hercynian’ unconformity by Late Carboniferous-Early Permian Al Khlata fluvial/glacial erosional valleys.

In the area where the Sahmah Formation is present it is the youngest formation that subcrops the ‘Hercynian’ unconformity (Figures 1 and 2). The position of the erosional edge of the Sahmah Formation, towards the east and south, is somewhat uncertain as its delineation is only based on the well data available to this study.

Age of the Sahmah Formation

Petroleum Development Oman (PDO) interpreted the age of the Sahmah Formation as Early Silurian Llandovery and characterize it by PDO Biozone 1003 (Droste, 1997; A.R. Mohammed, J.A. Hussey and E. Rindel, PDO Report, 1997). Droste (1997) correlated the Sahmah Formation to the Qusaiba Member of the Qalibah Formation in Saudi Arabia (Mahmoud et al., 1992). The Qusaiba Member also consists of marine shales and, like the Sahmah Shale Member, the basal part is usually characterized by a ‘hot shale’. Sharland et al. (2001) positioned Maximum Flooding Surface MFS S10 in these hot shales, in Oman and Saudi Arabia, and attributed to MFS S10 an isochronous Llandovery age (Aeronian substage).

Robertson Research (Report, 2001), however, considers PDO Biozone 1003 (as interpreted in the Sahmah Shale in Burkanah-1) as Late Ordovician Ashgill. They noted that throughout the upper part of interval 3,840–3,879 m in Burkanah-1, the predominance of cryptospores, with moderately diverse chitinizoans, is typical of Biozone 1003 of Droste (1997). Droste (1997) assigns an Early Silurian age to Biozone 1003 but indicates the Plectochtina spongiosa (an Ashgill restricted chitinizoan) forms a characteristic element of the assemblage. Accordingly, Robertson Research prefers an Ashgill age for the Sahmah Shale, with some support from the recovered but limited acritarch assemblages.

In the Ata-1 well, Robertson Research (Report, 1999) interprets the Sahmah Shale as Ashgill, and the upper part of the Sandy Member as Llandovery in age (Figure 8). In the Aydan-1, Sahmah-1 and Rija-1 wells, Elf Aquitaine (Report, 1984) assigned the Sahmah Shale to the Llandovery.

The logs in Figures 8 support the lithological correlation of the Sahmah Formation from Burkanah-1 in the south, to Sahmah-1 in the north. The correlation suggests a prograding shelf, which would explain the differences in age. But is the paleontological evidence in Burkanah-1 in error and is the hot shale a Llandoveryaged isochronous interval representing a major flooding event (MFS S10, Sharland et al., 2001), or is it diachronous? The Qusaiba Shale in Saudi Arabia and Tannezzuft Shale in North Africa are both part of a prograding shelf sequences. The shales are dated by graptolites as Silurian, not Ordovician (e.g. Mahmoud et al., 1992) although the basal part of the Tanezzuft shale has recently been shown to be Ordovician (Lüming et al., 2003). The sample density in Sahmah-1 is such that it allows for the possibility of a very thin condensed Ashgill section in the basal part of the shale. It is also noted that Sharland et al. (2001) picked the MFS S10 above the base of the Qusaiba Shale. Further biostratigraphic studies are needed to reconcile the conflicting age interpretations.


Total Organic Carbon content (TOC) was measured in samples from the Sahmah Shale in Burkanah-1 (Table 1). The Burkanah samples show an increasing TOC with depth, and the highest values at the base of the Sahmah Shale (3.6%; Figure 11). Unfortunately, similar dense sampling and analysis was not available from the other wells for this study. G.J. Allison and A.M. Mackenzie (BP Report, 1984) list average TOC values for different wells in the area, and these range from 1–8%. As these values represent residual organic matter, the original content may have been even greater. The thickness and high TOC values of the Sahmah Shale indicate it is a good to excellent source rock (Table 1).

A gamma ray peak, 3–10 m thick, is often observed at the base of the Sahmah Shale (Figures 7 and 11). This peak corresponds to the part of the shale with the highest TOC, and thus to the effective source rock. Vitrinite reflectivity was measured in Burkanah-1 and Al Darmaa-1 (Figures 12 and 13), and data from other wells are listed in Table 1. The data exhibits a high scatter in the Paleozoic section and a fair trend in the Mesozoic section (Figures 12 and 13). The T-Max values range between 380° and 430°C for the Sahmah Shale showing the same scatter as the Ro values (Table 1). In order to verify the Vitrinite and T-Max measurements, especially in the Paleozoic section, additional maturity indicators were acquired. The Spore Coloration Index (SCI) (Robertson Research, Report, 2001) for both the Al Darmaa-1 and Burkanah-1 wells (Figure 15) were correlated to Ro (Table 3). The SCI from the Sahmah Shale is 8.5 in Burkanah-1 and 5 in Al Darmaa-1, corresponding to an equivalent Ro of 1.2% and 0.46%, respectively.

To better discriminate between true vitrinite and other macerals, Vitrinite-Inertinite-Reflectance and Fluorescence (VIRF) measurements were also taken from Paleozoic samples from the two wells. Although this method is still in its infancy, it is believed to provide a better indication of maturity (J. Newman, report for Maersk Oil, 2002). The VIRF measurement is 2% in Burkanah-1 for the Sahmah Shale.

Therefore, the additional indicator suggests that the maturity of the Sahmah Shale in Burkanah-1 should be in the range of 1.3 and 2.0% Ro; i.e. post mature for oil generation whereas the shale is immature in Al Darmaa-1.

Some of the T-Max values are low when compared to the estimated equivalent Vitrinite Reflectivity. They tend to follow the scatter of the measured Vitrinite reflectivity, and the higher values are believed to better reflect the maturity.

Source-to-oil Correlation

In Oman, six oil types have been identified (Terken et al., 2001). Some of the oil types can be related to a specific source rock, while others are more uncertain with regard to their origin. Table 2 lists the oil families and their possible corresponding source rocks.

The ‘B’ oil is only present in the Sahmah field, and according to Terken et al. (2001) it is tentatively correlated to the Sahmah Shale, as consistent with the findings of J.G. Allison and A.M. Mackenzie (BP Report, 1984). The analysis of the Sahmah oil suggests it is highly mature, thus implying an equivalent vitrinite reflectance of 0.9–1.0%.

The Aydan-1 well (Figure 10) penetrated a 42 m section of the Sahmah Shale Member, situated immediately below the Al Khlata Formation. Analytical work confirmed the presence of excellent source rock qualities in the shale (Table 1). A production test in the lowermost part of the oil-bearing basal part of the Gharif Formation sandstone recovered 1.5 cubic meters of oil. An oil-to-source rock correlation established that this oil was most likely generated from the Sahmah Shale. The oil is similar to the ‘B’ oil in Sahmah field that has a catagenetic stage corresponding to an eRo of 1.1–1.3% (Elf Aquitaine Report, 1984).

Minor hydrocarbon shows have also been encountered in siltstone stringers in the basal part of the Sahmah Shale in the Burkanah-1, Al Hashman-1, Wadi Quitbit-1 and Ata-1 wells. Hydrocarbon shows are also evident by the increase in resistivity over the siltstone stringers in Burkanah-1 and Wadi Quitbit-1 (Figures 7 and 11).


Burial History

A basin model of the Sahmah Shale Member was developed using the Petromod software and data from 13 wells (Table 4 and Figure 16). The stratigraphic framework (A.R. Mohammed, J.A. Hussey and E. Rindel, PDO Report, 1997; Sharland et al., 2001) and corresponding burial histories, for Al Darmaa-1, Burkanah-1 and Sahmah-1, are shown in Figures 46. To construct the burial histories several assumptions were required for the duration and extent of uplift and erosion, especially for the ‘Hercynian’ unconformity.

In Oman, the ‘Hercynian’ unconformity represents two (or more) erosional events. The oldest event is represented by a time hiatus from the late Early Silurian to the late Early Devonian. The second represents one or more hiatuses in the late Middle Devonian to the early Late Carboniferous. Between the two events, the intermediate period is represented by the deposition of the Misfar Group.

The Misfar Group is present in central Interior Oman (Figure 1), and rests on Lower Ordovician (Ghudun Formation) or older strata (A.R. Mohammed, J.A. Hussey and E. Rindel, PDO Report, 1997). Reworked Middle and Upper Devonian palynomorphs suggest that a more complete Devonian section was present prior to erosion. Konert et al. (2001) discussed the distribution of the Silurian-Devonian sediments on the Arabian Plate. Lower Devonian sediments are missing in Iraq and Turkey whereas a complete Devonian section is present in Saudi Arabia. Therefore Devonian sediments were probably also deposited in Oman and subsequently eroded during the Carboniferous.

In the model, it is assumed that about 300 m of Misfar Group sediments were deposited over the entire area (based on the maximum measured thickness in Oman), and subsequently eroded. This assumption is important for the burial history component of the model.

Surface Temperature and Bathymetry

The surface temperature (Figure 16) was based on the paleo-latitudes of the Arabian Plate and paleobathymetry interpreted from the facies maps for the various formations (Konert et al., 2001; Ziegler, 2001). For example, for the Late Carboniferous and Early Permian times, the glacial deposits of the Al Khlata Formation suggest a low surface temperature in a continental environment. Since the Permian, in contrast, the absence of deeper-water facies and the lower latitudes of the plate suggest warmer surface temperatures and moderate water depths. The surface temperature reconstruction for the Burkanah-1 well was used as the default for all models (Figure 16).

Geochemical Parameters

In the model, all kerogens were assumed to yield 450 mg oil and 50 mg gas per gm/TOC (D. Waples, Report for Maersk Oil, 2002). The TOC values for the Sahmah Shale are listed in Table 5. Unfortunately, there is no petroleum kinetics data available for the Sahmah Shale. The Petromod software provides several options for kinetic models, and the Silurian Qusaiba Shale was used because it is the most similar analog source rock with kinetic measurements (Abu Ali et al., 1999).

Calibration of the Model

The calibration data for the model consists of down-hole temperature measurements, and in some of the wells maturity data such as Ro and VIRF (Table 4). Present-day temperatures were optimized by adjusting the present-day basal heat flow until a satisfactory fit was achieved between the recorded and adjusted down-hole temperatures, and the calculated temperature profile (D. Waples, Report, 2002) (Figure 12-16). The resulting heat flow values are shown in Table 5.

Due to the limited tectonic activity, the paleoheat flow values were assumed to be constant for the period from Ordovician to present. This is because the tectonic history does not suggest significant heat pulses following the deposition of the Sahmah Shale Member. Nor would any early heat pulse affect the maturity significantly, only late heating would do so. Therefore the mean heat flow values are expected to range between 40 and 70 mW/sq m (Allen and Allen, 1990). Accordingly, the maximum heat flow value was limited to 70 mW/sq m.

The model heat flow trend increases from 30 mW/sq m in the southeast, to 70 mW/sq m in the northwest and in the center of the Rub’ Al-Khali Basin. The highest value of 65 mW/sq m occurs near the Burkanah-1 well. Milner (1998) reported a similar trend, but with generally lower values of 30–50 mW/sq m. The discrepancy is believed to be due to differing calibrations and software. Also, the model presented here benefited from new data in south Oman, which was not available to Milner (1998). The only way to lower the heat flow values would be to accept significant Miocene erosion at the Burkanah location, which does not seem likely.

Results of the Basin Model

The basin model predicts Vitrinite Reflectance (Ro) in percent (Figure 17 and Table 5), and the time for the onset of petroleum generation for each well. The model Ro shows the highest maturity in the deepest part of the basin (1.74% in Burkanah-1). Due to the reduced overburden thickness, the maturity diminishes towards the edge of the basin (0.5% in Al Darmaa-1; Figure 17). In Burkanah-1 (Figure 4), the model suggests the onset of oil generation commenced in Late Cretaceous time (~100 Ma), implying that oil migration just preceded the obduction event in Oman, and the associated thrusting and structural deformation.

In the Sahmah-1 well in central Interior Oman, the Sahmah Shale is not deeply buried and does not match the high maturity encountered in Burkanah-1. In Sahmah-1, oil generation commenced in Early Tertiary time, and the shale is currently in the late oil window (Figure 6). The timing of structural development in Sahmah-1 and Burkanah-1 is similar; however, the time intervals for trap formation and hydrocarbon generation are more favorable in the Sahmah field (compare Figures 4 and 6).

(Robertson Research, Report, 2001)


From regional geological considerations and from the geochemical modeling presented here, the existence of two different petroleum systems may be inferred: (1) Sahmah Shale:Gharif(!); and (2) Sahmah Shale:Hasirah(?). The following discussion emphasizes the position of the kitchen areas and the possible migration routes.

The Sahmah Shale:Hasirah(?) Petroleum System

The Sahmah Formation in the Burkanah-1 well is 525 m thick (Figure 9) and the Sahmah Shale source rock is positioned at its base. Because the source rock lies below many sealing intra-Sahmah shale layers, vertical migration is impeded. It is therefore more likely that hydrocarbons will be downcharged into the underlying sandstones of the Hasirah Formation (Figure 18). During the Cretaceous, the Hasirah sandstones were buried 800 m shallower than today, and hence more of the original porosity and permeability was preserved.

The oil that was initially generated would have migrated up dip into the uppermost Hasirah sandstones. However, due to the lack of structural traps at that time, most of this oil was probably lost. The gas that was subsequently generated, however, would be trapped. Due to burial diagenesis, these sandstones are presently extremely tight in the deeper part of the basin (Konert et al., 2001), and in Burkanah-1.

These considerations may explain the presence of residual hydrocarbon saturation that is occasionally encountered in the tight siltstone stringers in the basal part of the Sahmah Shale (e.g. the Burkanah-1 well at 3,905–3,925 m below drill floor, Figure 7), and uppermost tight Hasirah sandstones (e.g. Ata-1 well 3,708–3,720 m below drill floor, Figure 7).

The Hasirah Formation in Al Darmaa-1 was never buried too deeply (less than 2,000 m, Figure 5), and this resulted in a relatively high porosity (20–25%). In this well, however, the Sahmah Shale is immature. This implies that during the Tertiary time, the Sahmah source rock generated oil (at a position between Burkanah-1 and Al Darmaa-1) that migrated into the porous Hasirah sandstone. Therefore the area between Burkanah-1 and Al Darmaa-1 is prospective for oil entrapment (Figure 19). In the area north of Burkanah-1, the later-generated gas could be trapped if the Hasirah sandstone is porous.

Sahmah Shale:Gharif(!) Petroleum System

In Sahmah-1, the Sahmah Shale is shallower and less mature than in Burkanah-1. Here oil generation commenced in Early Tertiary and coincided with the development of the Sahmah structural trap (Figure 6). In the Sahmah area there are two possible migration pathways: either charging into the underlying Hasirah sandstone, as described above; or charging into the overlying sediments. The latter pathway is applicable at the erosional edge of the Sahmah Shale (Figure 18).

To estimate the regional extent of the Sahmah Shale ‘Hercynian’ subcrop it is assumed that the effective source rock interval is 10 m thick. Because the ‘Hercynian’ unconformity dips at an angle of less than one degree, the source rock interval below the unconformity will form a 1,000–1,500 meter-wide corridor. This is the corridor zone in which the source rock can charge the overlying Al Khlata or/and Gharif formations (Figure 18). Because the Al Khlata, in the Sahmah area, is mostly sandy it does not restrict vertical migration. The first effective seal is the basal shale of the overlying Gharif.

Due to local erosion, the exposure zone is more irregular than indicated above, and the area with vertical charge is probably as wide as indicated in Figure 19. The current database does not allow for a more detailed mapping of the exposure zone. The proximity of the Sahmah field (‘B’ oil in the Gharif reservoir) to the subcrop of the Sahmah source rock, is an example of the migration pathway. This exposure zone constitutes the area for the Sahmah Shale:Gharif(!) Petroleum System.


The Sahmah Formation of Oman consists of the lower Shale and upper Sandy members, and reaches a thickness of more than 500 m. It extends across south and west Interior Oman, and into the Rub’Al-Khali Basin in southern Saudi Arabia. The basal 3–10 m of the lower Sahmah Shale Member is a good to excellent source rock with Total Organic Carbon content of up to 8%. The basal Sahmah Shale is the source for the ‘B’ oil in the Gharif reservoir in the Sahmah field in central Interior Oman, and several of the oils tested in the vicinity of this field. In this area, the source rock became mature and started generating hydrocarbons during Tertiary time, after the Sahmah field trap was formed. Where the erosional edge of the Sahmah source rock subcrops the sandy Al Khlata Formation, the overlying sandstones of the Gharif Formation can be charged. This is the area of the Sahmah Shale:Gharif(!) Petroleum System.

Towards the Rub’ Al-Khali Basin, the preserved Sahmah Formation is much thicker than near the Sahmah field. In this region the formation is thick, and intra-formational shales act as a seal to vertical migration of hydrocarbons from the basal Sahmah source rock. Here, only downwards charging into the Hasirah sandstones is possible, and this is the area of the Sahmah Shale:Hasirah Formation(?) Petroleum System. This system is restricted to the area where the Sahmah Shale is in the oil or gas window, and the Hasirah sandstone has not lost all its porosity due to burial diagenesis.


The author expresses his thanks to the Ministry of Oil and Gas of the Sultanate of Oman, and Maersk Oil Oman BV for permission to publish this paper. Åke Hesselbom, Rene Thomsen and Gavrielle Groves-Gidney have read earlier versions of this paper, and their comments were very valuable in improving the manuscript. The author thanks two anonymous GeoArabia reviewers for their useful comments; and GeoArabia’s staff for their assistance in editing the final manuscript and designing the paper for press. The manuscript was proofread by GeoArabia Editor Peter Jeans, 10 June 2004.


Nick Svendsen is an Exploration Geologist with the Danish oil company, Maersk Oil. He graduated from Copenhagen University in 1975 as a Carbonate Geologist and joined Maersk Oil in the same year. He has worked as a Wellsite Geologist, Development Geologist and Exploration Geologist. Nick’s university experience with the Cretaceous Chalk enabled him to advance the understanding of the then barely understood chalk reservoir. In 1981, he was seconded to Shell in The Hague to work on the Tyra field (chalk reservoir) in the Danish North Sea. Following that he was seconded to Petroleum Development Oman (PDO) in Oman, where he worked as Development Geologist on the Fahud and Natih fields. Returning to Maersk Oil in December 1984, Nick moved to the Exploration Department and has since worked projects such as Algeria, Ecuador, Oman, Qatar and Thailand.