Sandstones of the Early Paleozoic Miqrat Formation and Barik Sandstone Member (Haima Supergroup) are the most prolific gas/condensate containing units in the northern part of the Interior Oman Sedimentary Basin (IOSB). The reservoir-quality of these sandstones, buried to depths exceeding 5 km, is critically related to the depositional environment, burial-related diagenetic reactions, the timing of liquid hydrocarbon charge and the replacement of liquid hydrocarbon by gas/condensate.
The depositional environment of the sandstones controls the net-sand distribution which results in poorer reservoir properties northwards parallel to the axis of the Ghaba Salt Basin. The sandy delta deposits of the Barik Sandstone Member have a complex diagenetic history, with early dolomite cementation, followed by compaction, chlorite formation, hydrocarbon charge, quartz and anhydrite precipitation and the formation of pore-filling and pore-lining bitumen. In the Miqrat Formation sandstone, which is comprised of inland sabkha deposits, similar authigenic minerals occur, but with higher abundances of dolomite and anhydrite, and less quartz cement. The deduced pore water evolution from deposition to recent, in both the Miqrat Formation and the Barik Sandstone Member, reflects an early addition of saline continental waters and hydrocarbon-burial related mineral reactions with the likely influx of lower-saline waters during the obduction of the Oman Mountains.
Four structural provinces are recognized in the IOSB based on regional differences in the subsidence/uplift history: the Eastern Flank, the Ghaba and Fahud Salt Basins and the Mabrouk-Makarem High. In the Fahud Salt Basin, biodegradation of an early oil charge during Late Paleozoic uplift resulted in reservoir-quality degradation by bitumen clogging of the pore space. On the Eastern Flank and the Mabrouk-Makarem High, however, the early oil bypassed the area. In contrast, post-Carboniferous liquid hydrocarbons were trapped in the Mabrouk-Makarem High, whereas on the Eastern Flank surface water infiltration and loss of hydrocarbons or biodegradation to pore occluding bitumen occurred. In the Ghaba Salt Basin, post-Carboniferous hydrocarbon charge induced a redox reaction to form porosity/permeability preserving chlorite in the reservoirs. The liquid hydrocarbons were replaced since the obduction of the Oman Mountains by gas/condensate which prevented the deep parts (>5,000 m) of the Ghaba Salt Basin from pore occluding pyrobitumen and thus deterioration of the reservoir quality.
Since 1984, when Petroleum Development Oman LLC (PDO) started to explore for non-associated gas reserves in north Oman, approximately 67 MMm3 condensate (95 MMm3 expected) and 14 TCF gas (18 TCF expected) have been found in Early Paleozoic siliciclastic reservoirs of the Haima Supergroup at depths between 4,200 and 5,200 m. The great depth of the prospects and the complex stratigraphy and depositional environments of the Haima Supergroup are main uncertainties for reservoir quality prediction. In this context we present the results of an interdisciplinary study whose goal was to decipher the complex interplay between depositional environment, diagenesis, burial, uplift and hydrocarbon charges in order to enhance reservoir property prediction on a basin-wide scale. The Early Paleozoic age of these prospects is an important indication that yet undiscovered but commercially exploitable hydrocarbons may exist in deeply buried Early Paleozoic rocks.
The Sultanate of Oman is situated in the southeastern corner of the Arabian Peninsula. Its Interior Oman Sedimentary Basin (IOSB) is a desert area between the Oman Mountains in the north and the Dhofar area in the south. To the east, the IOSB is bounded by the Huqf-Haushi axis, a NNE to SSW running positive structure, to the west, the basin grades into the Rub’ Al-Khali Basin of Saudi Arabia (Figure 1). In contrast to the intensely studied geology of the Oman Mountains, relatively little has been published on the geology of the interior of the country (Tschopp, 1967; Al-Marjeby and Nash, 1986; Hughes Clarke, 1988; Levell et al., 1988; Visser, 1991; Loosveld et al., 1996; Droste, 1997). Based on the tectonic history (Loosveld et al., 1996) and stratigraphy (Hughes Clarke, 1988), the IOSB can be subdivided into a southern area, the South Oman Salt Basin with its Eastern Flank and a northern area, the Ghaba and Fahud Salt Basins, the Mabrouk-Makarem High and the foreland area of the Oman Mountains (Figure 1).
The tectono-stratigraphic evolution of the IOSB (Figure 2; Loosveld et al., 1996; Terken and Frewin, 2000) began with the Pan-African accretion of the Gondwana continent as part of the Arabian Plate. Sedimentation started in extensional basins (Abu Mahara Group) of Neoproterozoic age followed by deposition during regional subsidence (Nafun Group) due to subduction at the NE-margin of the Arabian Plate. Basin-wide compression in the Ediacaran/Early Cambrian caused the formation of fault-bounded basins with the deposition of the Ara Group and the Haima Supergroup sequences. Epeirogenetic salt movements and NW-SE basin contractions since Ordovician generated uplift and erosion of Paleozoic strata, resulting in a major unconformity and lack of Upper Silurian to Lower Carboniferous sediments in Oman (Loosveld et al., 1996). The Late Carboniferous to Middle Triassic is marked by thermal doming which led to the break-up of Gondwana, opening of the Neo-Tethys and the development of a passive margin in North Oman. Renewed uplift during Late Triassic is related to the break-away of India and the development of a passive margin in Eastern Oman in Jurassic times. Closure of the Neo-Tethys since Late Cretaceous resulted in the formation of a foreland basin and the obduction of the Oman Mountains (Glennie et al., 1974). Soon after, the oblique convergence between Greater India and Afro-Arabia at the Cretateous-Tertiary boundary caused obduction of the Batain Nappes along the SW coast (Schreurs and Immenhauser, 1999; Immenhauser et al., 2000). Renewed subduction offshore SE-Iran brought temporary relaxation during Early Tertiary, but convergence between Eurasia and Arabia along the Zagros suture led to the completion of the mountain building process in the Oman Mountains (Le Métour et al., 1995).
Based on the tectonic setting four structural provinces are recognized in the IOSB, each with a characteristic burial history (Figure 3): the Eastern Flank and central area of the Ghaba Salt Basin, the Mabrouk-Makarem High and the Fahud Salt Basin. Modeling of the burial and temperature histories is constrained predominantly by apatite fission track analysis. Seismic data and shale compaction trends were used to quantify missing overburdens. A detailed description of the modeling input parameters, the assumed heat-flow, surface temperature and burial histories are given in Terken et al. (2001).
The Eastern Flank of the Ghaba Salt Basin experienced a phased, but progressive uplift and tilting with influx of surface waters during Late Devonian to Early Carboniferous, Late Triassic and at the Cretaceous-Tertiary boundary caused by thermal doming prior to the break-up of Gondwana, the failed break-off of India and the oblique convergence of Greater India on the Arabian Plate, respectively. These phases of uplift and tilting were followed by sedimentation, but net-burial was mostly during Permo-Carboniferous (Figure 3a).
In the central area of the Ghaba Salt Basin, formation of fault basins led to the deposition of thick sedimentary sections during the Ediacaran to Early Silurian. Salt down-building as a result of differential loading initiated the first trap-structures. Eastern Flank tilting after the Late Devonian induced salt doming and further formation of trap structures in the Haima Supergroup. Renewed sedimentation started in the Late Carboniferous with deposition of the Haushi Group and Akhdar Group followed by a new phase of rifting and thermal doming which ultimately led to the break-off of Gondwana. After a phase of uplift, probably due to the failed opening of the Indian Ocean, the area became part of the east Oman passive margin and is characterized by continuous subsidence with short times of minor uplift during emplacement and uplift of the Oman Mountains and the oblique convergence of Greater India and Afro-Arabia (Figure 3b).
The Mabrouk-Makarem High (Figure 3c) and the Fahud Salt Basin (Figure 3d) to the west of the Ghaba Salt Basin experienced only shallow burial during Huqf and Haima Supergroup times due to less subsidence and sedimentation. The pattern changed slightly with deposition of the Haushi Group, which has similar thicknesses all over the northern IOSB. Opening of the Neo-Tethys and formation of a passive margin in north Oman caused greater subsidence in the area of the Fahud Salt Basin and thus forming a positive structure, the Mabrouk-Makarem High, towards the Ghaba Salt Basin. This differentiation is amplified by increased sedimentation in the NW region of the IOSB during Jurassic and Early Cretaceous times.
Recent exploration in North Oman for gas and condensate provided a significant number of well penetrations, with abundant core material and sidewall samples from the Haima Supergroup. A detailed overview of the stratigraphy, tectono-stratigraphic evolution and lithostratigraphic definitions of this unit is given in Droste (1997).
The Cambrian to Lower Silurian Haima Supergroup represents a late syn- to postrift siliciclastic infill of an extensive graben system which is divided by major unconformities into the Lower Cambrian Nimr Group, the Lower Cambrian to Lower Ordovician Mahatta Humaid Group and the Middle Ordovician to Lower Silurian Safiq Group (Figure 2) (Droste, 1997). In northern Oman, the sandy to clayey Nimr Group is undifferentiated and restricted to the central parts of the salt basins. The Mahatta Humaid Group comprises the conglomeratic to sandy Amin and Miqrat formations and the sandy to clayey Andam and Ghudun formations, which are all separated by unconformable boundaries. The top unit of the Haima Supergroup is the sandy to clayey Safiq Group (for more details see Droste, 1997). In north Oman, the main Haima Supergroup reservoir intervals are located in the Amin Formation, the Upper Member of the Miqrat Formation, the Barik Sandstone Member of the Andam Formation and the Ghudun Formation. The most important basin-wide seal is the shaly Al Bashair Member separating the Miqrat Formation from the overlying Barik Sandstone Member (Figure 2).
The depositional environment during Haima Supergroup time was initially continental, but later a more marine influenced deltaic setting prevailed (Figure 4). At least six major transgressive-regressive cycles can be recognized and regionally correlated (Droste, 1997). The undifferentiated basal Nimr Group contains proximal alluvial fan and lacustrine playa lake deposits. The overlaying lower part of the Mahatta Humaid Group is continental and contains alluvial fan and aeolian (Amin Formation) and inland sabkha (Miqrat Formation) dominated deposits. The Miqrat Formation sandstones formed as sheetflood units in a low-relief sandflat/sabkha environment, probably on the southern margins of a large lake. Periodic base level changes allowed the development of extensive playa lakes (Droste, 1997). The overlaying Andam and Ghudun formations form three major transgressive-regressive cycles in which the Barik Sandstone Member (Andam Formation) represents a sandy braided delta system prograding across a very shallow shelf. The Safiq Group at the top of the Haima Supergroup represents a cyclic alteration of deeper water mass flows, shelf sands and fluvial deposits. The occurrence of cryptospores within the Safiq Group suggest that land vegetation already existed (Droste, 1997).
FACIES DISTRIBUTIONS AND OCCURRENCE IN MIQRAT FORMATION AND BARIK SANDSTONE MEMBER
Both the Miqrat Formation and the Barik Sandstone Member of the Andam Formation are present in central Oman with a maximum thickness of 350 m and 550 m, respectively. The isopachs of both units run parallel to the axis of the Ghaba Salt Basin (Figures 5 and 6).
The Miqrat Formation consists of red-brown micaceous shales and siltstones intercalated with fine- to very fine-grained sandstones. The Lower Miqrat Member represents a gradual retreat of extreme distal sheetfloods, resulting in an extensive sabkha with minimal sand input. Conglomeratic sands at the base of the formation are of fluvial origin and restricted to outcrops in the southern Huqf-Haushi area. The Upper Miqrat Member deposition started with progradation of extremely distal sheetfloods across this sabkha, followed by relatively dry sabkha conditions with some aeolian influence. Major aeolian activity, as shown by large-scale cross-bedding in the Huqf-Haushi outcrops, is located at the southeastern edge of the Ghaba Salt Basin. Only thin beds of aeolian sand are present farther to the north in the central part of the Ghaba Salt Basin where most sands have been deposited by sheetfloods. Wireline logs indicate that the sands become thinner, with a lower net-to-gross ratio and more argillaceous towards the north (Figure 5).
The Barik Sandstone Member consists of gray and red, cross-bedded, fine-grained sandstones with erosional bases. Fragments of trilobites and lingulid shells may occur in lags at the top of stacked sandstone units. Local intercalations of up to 5 m thick reddish mudstones with thin parallel to wave-rippled silt- to sandstone laminae are present. The sandstone dominates the more proximal locations as fluvial channels with intercalated floodplain heteroliths (e.g. Barik field), whereas in the more distal parts (e.g. Saih Rawl and Saih Nihayda fields) tidally influenced channels grade into mouthbar/shoreface sandstones punctuated by tidal flat/marine heteroliths (Figure 6; Droste, 1997). Paleocurrent directions determined on FMI/FMS logs from cross-bedded fluvial/tidal channel sandstones indicate a transport direction towards the northeast to northwest.
A total of 35 and 125 sandstone samples from the Miqrat Formation and the Barik Sandstone Member, respectively, were analysed (for details on material and methods used see Appendix). Sandstones from the Miqrat Formation and Barik Sandstone Member have a rather uniform composition in terms of quartz, feldspar and rock-fragments. The majority of the analysed samples are classified after McBride (1963) as arkoses and subarkoses, and rarely lithic subarkoses and quartzarenites. Modal analyses revealed that the most common detrital component is monocrystalline quartz (22–62%) with subordinate polycrystalline quartz (< 13%). Both, K-feldspar (2–32%) and plagioclase (0–19%) are present with K-feldspar being dominant. Variable amounts (< 15%) of lithic fragments, mainly high-metamorphic basement rocks and sedimentary fragments (chert, shales), are present besides biotite and muscovite. Shaley matrix is present, but difficult to distinguish from authigenic illite and/or shale fragments. Composition does not change as a function of grain-size and depositional environment.
A variety of diagenetic alterations are observed in the sandstones of the Miqrat Formation and the Barik Sandstone Member (Figure 7). Processes responsible for these alterations include mechanical and chemical compaction, dissolution of feldspar, precipitation of quartz, dolomite, calcite, anhydrite, barite, chlorite, illite, K-feldspar and hematite cements, as well as the emplacement of hydrocarbons and the formation of bitumen.
Two diagenetic facies can be distinguished in the Barik Sandstone Member (Figure 8): a chlorite-dominated, gray-colored facies present in reservoir sandstones containing producible hydrocarbons and an illite-dominated, red facies in water-bearing sandstones. A complex diagenetic history is observed in the hydrocarbon reservoirs, with early red-bed type diagenesis including clay coatings on detrital grains with associated hematite, and dolomite cement, and later compaction, chlorite formation, partial illitization of chlorite, quartz and anhydrite cementation, hydrocarbon charge and the formation of pore-filling and pore-lining bitumen. In the water-leg the late-diagenetic phases differ with fibrous illite growing in pore-spaces instead of chlorite and bitumen impregnation. In Miqrat Formation sandstones a similar sequence of diagenetic events is present, but with higher amounts of dolomite and anhydrite, and less quartz cement (Figure 8).
Red-bed Type Alterations
Clay coatings on detrital grains formed by mechanical infiltration and associated hematite, which gives the rock the characteristic red coloration, are the earliest modifications observed in the sandstones (Figure 7a). Rubidium/strontium isotope analyses of illite-bearing dolomite cements from the Barik Sandstone Member with 87Rb/86Sr > 1 yielded an isochron age of 480 ± 20 Ma with an initial 87Sr/86Sr ratio of 0.7097 ± 26. The > 1 87Rb/86Sr ratio and its covariant trend with the illite/dolomite ratio clearly indicate leaching of the illitic coatings and dissolution of dolomite during preparation of the sample for Sr isotope analysis. This Early Ordovician isochronal age supports a syn-depositional to early diagenetic origin of these clay coatings.
Dolomite, the most important carbonate cement, occurs in samples from the Ghaba Salt Basin as coarsely crystalline cement forming up to 10 cm thick dolocrete-like layers, micro-nodules up to a few millimeters wide with a higher intergranular volume (up to 30%) than the surrounding host sandstone (Figure 7b) or as traces of rhombic dolomite crystals (Figure 7d). The coarsely-crystalline dolospar is composed of poorly defined, nonplanar crystals that typically show undulose extinction. High abundances of dolomite correlate in the Barik Sandstone Member with poorer reservoir quality, i.e. lower porosity and permeability values (Figure 9). The highest dolomite contents are observed in floodplain heteroliths or tidal flat sandstones. In contrast, sandstones with a low abundance of dolomite (< 2%) are typically channel and mouthbar/foreshore sandstones of good reservoir quality. Thus, the distribution of dolomite is facies-dependent, which is consistent with an early diagenetic origin. In samples from the Mabrouk-Makarem High, however, there is evidence for a later-diagenetic phase of dolomite which engulfs thin overgrowths of quartz cement.
Stable isotopic analyses of dolomite cements in the Barik Sandstone Member define a covariant trend ranging from -9.5‰ to 1.2‰ in δ13C and from -19.2‰ to -3.1‰ in δ18O (Figure 10). Lighter isotopic values of < -4‰ in δ13C and < -11‰ in δ18O, are typically found in samples from the Mabrouk-Makarem High, whereas samples with heavier values are from the Ghaba and Fahud Salt Basins (Figure 10). This supports the interpretation of a later-stage origin of dolomite at the Mabrouk-Makarem High and the possibility of two causes for the observed covariant trend, i.e. evaporation during dolocrete formation and mixing during burial. The few samples from the Miqrat Formation sandstones show the same trend with the distinction between high and basinal position, but with two samples off the trend (Figure 10).
Strontium isotope ratios of reliable analyses, i.e. those with 87Rb/86Sr < 0.5, scatter after correction for an age of 480 Ma from 0.7075 to 0.7140. For 57 out of 58 samples, the corrected 87Sr/86Sr ratios are all within or more radiogenic than the range of Cambrian to Ordovician seawater, i.e. between 0.7092 and 0.7079 (Nicholas, 1996; Veizer et al., 1999).
Primary fluid inclusions in early-diagenetic dolomite cements from the Barik Sandstone Member in the Ghaba Salt Basin are all single-phase, liquid aqueous inclusions with inferred homogenization temperatures (Th) of ≤ 50 °C (Goldstein and Reynolds, 1994). In later-stage dolomite cements from the Mabrouk-Makarem High two-phase, liquid-rich aqueous inclusions are present with homogenization temperatures ranging from 125 to 161°C. Taking these homogenization temperatures as minimum formation temperatures of dolomite cement in the Barik Sandstone Member, the onset of dolomite precipitation in the Ghaba Salt Basin is in the Early Paleozoic soon after deposition and at about 110 Ma on the Mabrouk-Makarem High (Figure 3). Thus, the later-stage origin of dolomite at the Mabrouk-Makarem High as indicated by petrographic evidence is consistent with the inferred timing based on isotope and fluid inclusion data. Freezing point depression values (Tm(ice)) vary for the first group between -11.9 and -24.2°C whereas for the high-temperature inclusions this range is from -14.3 to -19.4°C (Tables 2 and 3). In the case of all-liquid inclusions there is an apparent positive correlation between Tm(ice) and the eutectic temperature (Te) with lower Tm(ice) values corresponding to lower Te values. Th- and Tm(ice)-values for primary fluid inclusions in the Miqrat Formation sandstone are 125 to 145°C and -15.6 to -22°C, respectively, for the Ghaba Salt Basin and 123°C and -17.4°C, respectively, for the Mabrouk-Makarem High (Tables 2 and 3).
Authigenic chlorite is a common cement in the gray-colored reservoir sandstones of both the Miqrat Formation and Barik Sandstone Member. It occurs predominantly as pore-lining rims on the detrital grain surface (Figure 7c). Backscatter electron images reveal that these rims are composed either of well-developed chlorite flakes of ≤ 10 μm size commonly arranged in a rosette, such as in the Saih Rawl and Barik fields, or of small (≤ 5 μm), thin irregular platelets showing a poorly developed box work fabric as in the Saih Nihayda field (Figure 11). Pore-lining chlorite never occurs where dolomite is present but is enveloped by later-stage anhydrite and bitumen. The paragenetic relationship to quartz cement is more difficult to determine as either pore-lining chlorite or quartz overgrowths are present in pore-spaces. In rare cases, quartz grains are covered with patches of chlorite directly coating the detrital grain and patches of quartz overgrowth forming primarily on clean detrital surfaces. Often these quartz overgrowths partly cover the chlorite patches (Figure 7c) indicating that quartz postdates chlorite.
Chemical analyses show that chlorites in the Saih Rawl and Barik fields have a Fe/[Fe+Mg] ratio between 0.65 and 0.3, whereas those in the Saih Nihayda field with irregular morphology have a Fe/[Fe+Mg] ratio of < 0.2 (Figure 11). Chlorites in the Miqrat Formation sandstones are distinct with less Si substituted by Al than chlorites from the Barik Sandstone Member (Figure 11). All examined chlorites are Mg-chlorites and of the IIb polytype.
Oxygen and hydrogen stable isotope analyses of chlorites yield δ18O values between 4.4 and 10.0‰ (V-SMOW), while the corresponding δD range varies from -64 to -30‰ (V-SMOW). Chlorites from the Miqrat Formation form a cluster at higher δ18O and more negative δD than chlorites from the Barik Sandstone Member (Figure 12).
K-Ar age dating of chlorite/illite intergrowths resulted in a range of ages between 168 Ma and 402 Ma. Samples analysed from the water-legs generally show a low chlorite/illite ratio and older ages than those from the gas-legs with pore-lining bitumen (Figure 13). The range of K-Ar ages for gas-leg samples in the Barik Sandstone Member is 168 and 330 Ma for the Barik and Saih Rawl fields. Single age dates for the Saih Nihayda field and the Jaleel-1 well (Figure 1) are 300 and 330 Ma, respectively. Chlorite/illite ages of the Miqrat Formation are about 100 Ma older than those in the Barik Sandstone Member.
Authigenic quartz occurs as syntaxial overgrowths on detrital grains (Figures 7c and 7d). Dust rims may be present between the detrital grains and the overgrowths. In a few samples from the Makarem-1 well (Mabrouk-Makarem High) authigenic quartz entirely occludes the intergranular pore-space, whereas in most other locations the abundance of authigenic quartz is lower, and the intergranular volume is partially open, or filled with dolomite, anhydrite, chlorite or bitumen (Figures 7c and 7d). Furthermore, sandstones from the Barik Sandstone Member contain generally less quartz cement than those from the Miqrat Formation. Quartz overgrowths are enclosed within anhydrite (Figure 7d), engulf chlorite (Figure 7c) and are not present in dolocretes. Thus, dolomite and chlorite generally predate quartz, whereas anhydrite is a later-stage cement.
Conventional δ18O analyses of the < 53 μm size fraction from sandstones of the Barik Sandstone Member and Miqrat Formation with abundant well developed syntaxial quartz overgrowths gave values between 14.6 and 18.1‰ (V-SMOW) and 14.3 and 15.5‰ (V-SMOW), respectively (Table 2).
Primary fluid inclusions at the boundary between detrital and authigenic quartz in samples from the Barik Sandstone Member and the Miqrat Formation are all two-phase, liquid-rich aqueous inclusions with homogenization temperatures (Th) ranging from 117 to 132°C and from 110 to 158°C for the Ghaba Salt Basin and the Mabrouk-Makarem High, respectively. Taking these homogenization temperatures as minimum formation temperatures of quartz cement in the Barik Sandstone Member and the Miqrat Formation, then the onset of quartz precipitation would be at 130 Ma and 110 Ma for the Ghaba Salt Basin and the Mabrouk-Makarem High, respectively. These maximum ages of quartz precipitation are clearly younger than the 330 to 168 Ma time span of chlorite growth and thus support the paragenetic indications. Freezing point depression values (Tm(ice)) vary for the Ghaba Salt Basin between -10.4 and -26°C and for the Mabrouk-Makarem High between -13.7 and -25.2°C (Tables 2 and 3). Tm(ice) and eutectic temperature (Te) values below -21.2°C clearly indicate that the salinity is not pure NaCl but contains also CaCl2 and likely other ions (Goldstein and Reynolds, 1994). Similar to the overlaying Al Khlata Formation (Juhász-Bodnár, 1999), a lower-saline period during quartz precipitation occurred in the Barik Sandstone Member and the Miqrat Formation (Table 3). Microthermometric data of primary two-phase fluid inclusions in quartz show generally an overlap of the homogenization temperatures with those of dolomite cement but not dolocretes indicating precipitation of the dolomite cement at identical burial temperature (Table 3).
Anhydrite is a minor authigenic constituent in many samples which typically occurs as poikilotopic nodules enclosing dolomite cement and quartz overgrowths and postdates significant mechanical compaction (Figures 7c and 7d). In few cases anhydrite also fills solution-enlarged pores and fractures. The sulfur isotope ratios from eight anhydrite cements of both formations and a fracture-filling anhydrite from the Fahud Salt Basin (Figure 1) vary between 20.4 and 30.6‰ (V-CDT). This range partly overlaps with the marine δ34S of Cambrian age (Walter et al., 2000), but is clearly lower than values from the Ediacaran/Cambrian Ara Group evaporites of South Oman (Schröder et al., 2004). However, a similar range of δ34S as in the anhydrite of the Haima Supergroup is known from the age equivalent Hormuz Formation in Iran (Strauss, 1993).
Strontium isotope ratios of anhydrite range from 0.7088 to 0.7172 (Table 1). These values are, with the exception of a coarsely crystalline fracture-filling anhydrite, significantly more radiogenic than the accepted range of Cambrian seawater (i.e. < 0.7092, Veizer et al., 1999). Moreover, anhydrite enclosing dolomite cement has always a more radiogenic 87Sr/86Sr ratio than dolomite (Table 1). Similarly, later formed coarsely crystalline anhydrite is slightly more radiogenic than earlier finely crystalline one (Table 1).
Anhydrite containing primary fluid inclusions was only found in a fracture-filling from the Barik Sandstone Member in the Fahud Salt Basin. The measured Th ranges from 138 to 162°C and Tm(ice), between -17.5 and -19°C (Table 2).
Pore-filling and pore-lining bitumen are typically present in the hydrocarbon-bearing gray facies of the Barik Sandstone Member. The pore-filling type is restricted to the Fahud Salt Basin (Figures 7f, 14 and 15), where up to 20 vol.% is occupied by pore-filling bitumen (Figure 15), with only small amounts of quartz cement. This high volume and the covariant trend between bitumen and pre-bitumen porosity (Figure 15) are indicative of an early oil charge followed by degradation to bitumen by water flushing with or without biodegradation and clogging of the pore-space for further mineral precipitation (Figure 7f). In contrast, the pore-lining type occurs in the Ghaba Salt Basin and at few localities on the Mabrouk-Makarem High, where it forms thin (≈2 μm) coats on chlorite and authigenic quartz. This second type is volumetrically insignificant and not related with the pre-bitumen porosity (Figure 15) and thus evidence for a later oil charge. At all gas fields, where the Miqrat Formation was drilled, only the pore-lining type of bitumen is present (Figures 14 and 15).
Hydrocarbon Related Mineral Reactions and Timing of Migration/Entrapment
An association exists in the Barik Sandstone Member between the occurrence of hydrocarbons and the dominance of chlorite relative to illite. Sandstones containing producible hydrocarbons are gray-colored and characterized by the presence of authigenic chlorite, whereas non-reservoir sandstones are mostly red-colored with the diagnostic presence of hematite, ± illite and ± anhydrite (Figure 8). This relationship is well known and represents a redox reaction between iron oxide, ± sulfate, ± illite and hydrocarbons to form chlorite, ± pyrite and organic acids (Surdam et al., 1993).
Evidences that chlorite is the product of the above stated hydrocarbon-involved reaction are: (1) All available petrographic, mineralogical and geochemical data (i.e. formation at < 110°C as evidenced from Th of fluid inclusions in authigenic quartz, Mg-rich chemistry and IIb polytype) suggest a deep-burial, high-temperature (80–110°C) origin of the chlorite cement (Hillier, 1994; Spötl et al., 1994; Hillier et al., 1996). (2) The K-Ar age dating of chlorite/illite intergrowths resulted in distinct groups with generally older ages in the water-leg than in the gas-leg (Figure 13). If detrital contamination or illite from the clay coatings would be the source of illite, then neither distinct age groups nor differences between the gas- and water-leg should exist.
Therefore, a close relationship between chlorite formation and liquid hydrocarbon charge/entrapment is apparent. The most satisfactory interpretation of the K-Ar dating results is that the apparent ages represent the date that diagenesis was completed in each of the rocks sampled. The results further suggest that at least two different diagenetic events have been dated: (i) samples from the water-legs below producible hydrocarbons record an earlier stage of illite diagenesis (~400 Ma), and (ii) samples from gas-legs are chlorite-dominated and show younger ages. Dating the chlorite formation as a product of redox reactions concurrent or shortly after hydrocarbon invasion into Haima sandstones could explain both the difference in ages between the water- and gas-legs as well as the down-hole increase in age. We interpret the K-Ar age dates as the timing of hydrocarbon charge/entrapment in the Barik, Saih Rawl and Saih Nihayda fields of the Ghaba Salt Basin, which thus occurred between 330 and 168 Ma.
Porosity and Permeability
Porosity and horizontal permeability (Kh) were determined on core plugs from sandstones of the Barik Sandstone Member and the Miqrat Formation (Table 4). Correlation between porosity and horizontal permeability in sandstones from the Barik Sandstone Member is generally good (Figure 16). Samples with low porosity and permeability values have higher amounts of early dolomite or anhydrite cements, whereas sandstones with high values have in general more secondary porosity (Figure 16), a high ln(chl/ill)-value (e.g. a high relative chlorite concentration) and mostly < 15% quartz cement.
Loss of primary porosity as determined from the compactional (COPL) and cementational (CEPL) porosity loss (Lundegard, 1992) in both the Barik Sandstone Member and the Miqrat Formation is dominantly the result of compaction, except for sandstones with high amounts of early dolomite cement (i.e. dolocretes), which generally have a cementational loss of primary porosity (Figure 17a). Moreover, a negative relationship was found between the COPL and the amount of quartz cement, i.e. the lower the quartz cement the greater the COPL (Figure 17b). The effect of chlorite, expressed as the ln(chl/ill)-value of the < 2μm clay-fraction, is less clear, but Figure 17c indicates that samples with a high ln(chl/ill)-ratio preferentially lost porosity by compaction. Integrating these data reveals that samples with high amounts of authigenic dolomite, quartz and chlorite cement form distinctive clusters in the COPL-CEPL cross-plot, with the chlorite cluster in the compactional field, the dolomite one in the cementational field and the quartz one in-between.
Present-Day Formation Water
Two formation water samples from the same well in the Barik Sandstone Member were analyzed for their chemical and O-, D- and Sr-isotopic composition (Table 5). Both analyses are similar and show that the present-day formation water in the Barik Sandstone Member at Saih Rawl is a Na-Ca-Cl brine with a TDS of 210 g/l. The ratio between measured concentrations of dissolved species and seawater, i.e. the evaporation factor, ranges in the analysed waters between 0.2 (diluted) and 118 (enriched). The slightly lower ratios for Na+ and Cl- than Br- is indicative that both constituents are not directly derived from evaporation of seawater or dissolution of halite but their concentrations are the combined effect of seawater evaporation past halite saturation and subsequent dilution (Wilson and Long, 1993). Species such as Mg2+ and SO42- are clearly depleted and Ca2+, Sr2+, Rb+ and Li+ are highly enriched relative to seawater. The depletion of Mg2+ and SO42- supports the earlier stated redox reaction to form Mg-chlorite through sulfate and hematite reduction, and dolomite and illite dissolution which results in an uptake of Mg2+ and Fe2+ but releases the highly enriched species Sr2+and Rb+ into the pore water. The ratios of 87Sr/86Sr and 87Rb/86Sr are generally higher and lower, respectively, than those determined in dolomite and in most of the anhydrite cements suggesting that these ratios are related to alumosilicate reactions, i.e. the redox reaction to form chlorite (Tables 1 and 4).
Thermodynamic equilibrium calculations with SOLMINEQ 88 (Kharaka et al., 1988) and the Pitzer-equation for activities of aqueous species in concentrated aqueous solutions (Pitzer, 1981) at surface (25°C, 1 bar) and bottom hole conditions (131°C, 400 bar) indicate saturation (± 0.15 log SI) of the two formation waters for quartz at surface conditions and for anhydrite at bottom hole conditions. All other common mineral phases such as halite, calcite and dolomite are under-saturated at surface and bottom hole conditions. Under-saturation of the carbonate phases is likely an artifact of the pH measurement in these highly concentrated brines with organic components as the carbonate system is highly pH dependent. Boiling of the formation water as a result of pressure release might be a possible explanation for the calculated under-saturation of quartz at bottom hole conditions. Thus, the difficulty of sampling and analyzing these hot (> 100°C), pressurized and highly saline formation waters with dissolved organic compounds is the likely cause for the calculated under-saturation of carbonates and quartz as they are present in the sandstones. Under-saturation of halite is likely real as no halite was observed in the Barik Sandstone Member at Saih Rawl.
Controlling Factors of Porosity and Permeability Evolution
The decrease from an assumed depositional porosity of ~ 45% (Lundegard, 1992) to present day values of 8.5 ± 3.3% (Barik Sandstone Member) and 5.5 ± 2.4% (Miqrat Formation) reflects the combined overprint of the depositional environment and climate induced early diagenetic alterations, burial related compaction, cementation, formation of secondary porosity, emplacement of hydrocarbons and their replacement by gas/condensate. Most of these processes are porosity destructive. Carbonate and anhydrite pervasively occlude the pore-space, whereas chlorite mainly delays further compaction and hinders quartz precipitation. Cementation by quartz reduces the pore-space but stabilizes the grain fabric against compaction. Plots of COPL versus CEPL reveal that compaction is the most effective porosity destructive process in the absence of early dolomite cement (Figure 17a). Samples with high amounts of chlorite and those with > 15% authigenic quartz form two distinctive clusters (Figures 17b and 17c), indicating that chlorite prevents quartz precipitation but not compactional loss of intergranular volume during further burial. Porosity was further reduced by compaction during the replacement of liquid hydrocarbons by gas/condensate. The cause of the negative correlation between the amount of quartz cement and the degree of compactional porosity loss (Figure 17b) is due to the framework stabilizing effect of quartz cement. The direct relationship between plug porosity and amount of secondary porosity suggests that the more porous layers acted as preferential conduits. Petrographic analyses confirm a late-stage origin of secondary porosity after pressure solution, quartz precipitation and exchange of liquid hydrocarbons by gas/condensate (Figure 7e).
In general, the present-day porosity and permeability are closely related to the timing of liquid hydrocarbon emplacement, the hydrocarbon induced chlorite formation (gray facies) and the replacement of the liquid hydrocarbon charge by gas/condensate. Thus, burial-related cementation is not only driven by temperature but by the lack of carbonaceous particles (which might be the reason for the lack of carbonate cement precipitated during early burial), the early diagenetic clay coatings prohibiting quartz precipitation and the timing of liquid hydrocarbon emplacement and exchange by gas/condensate.
Pore Water Evolution
Integration of petrographic, geochemical and fluid inclusion data of dolomite, anhydrite, chlorite and quartz cements from the central part of the Ghaba Salt Basin and the Mabrouk-Makarem High allow an interpretation of the pore fluid evolution in the reservoir sandstones during the ~500 Ma burial history. Because the sediments were deposited under semi-arid conditions in an inland sabkha as sheetflood and aeolian deposits with salt pseudomorphs (Miqrat Formation) and in a marine influenced, braided delta with fluvial channels, intercalated floodplain deposits and tidally influenced shallow-marine deposits (Barik Sandstone Member) suggests highly variable initial pore water salinities. Soon after deposition, the low-temperature single-phase aqueous fluid inclusions entrapped in early diagenetic dolomite from the Barik Sandstone Member reveal that the pore water salinity was extremely high and of a Na-Ca-Cl type (Table 2). Later, at elevated temperatures (> 100°C), entrapped fluid inclusions in quartz and dolomite cement record still high salinities of a Na-Ca-Cl type brine which is similar to present-day formation water in the Barik Sandstone Member (Saih Rawl field, Table 5). The low saline fluid detected in fluid inclusions in quartz cement may have been trapped at the same time as in the overlying Al Khlata Formation (Juhász-Bodnár, 1999). The similarity of the brines trapped in all fluid inclusions with those of the present-day formation water implies that the overall salinity and composition in the pore water has not changed significantly in the central area of the Ghaba Salt Basin over most of the 500 Ma burial history.
Isotopic ratios of strontium incorporated in dolomite and anhydrite cement document that the 87Sr/86Sr ratio increased from an age corrected value of 0.7075 in early diagenetic dolomite up to 0.7172 in late diagenetic anhydrite cement (Table 1) and present day formation water (Table 5). This increase in the 87Sr/86Sr ratio during burial implies incorporation of radiogenic 87Sr through liberation of rubidium by aluminosilicate alterations, i.e. clay mineral reactions and/or K-feldspar dissolution. The high 87Sr/86Sr and low 87Rb/86Sr ratio and the highly enriched Sr2+, Rb+ and Li+ concentrations in the formation water (Table 5) as well as the 480 Ma isochron age of illite are further evidence of clay mineral reactions in these rocks. Age corrected 87Sr/86Sr ratios for dolomite cement clearly show that the incorporated strontium has at least two sources, with one end member of Late Cambrian/Ordovician marine origin (i.e. 0.7092 to 0.7079, Nicholas 1996; Veizer et al., 1999) and a more radiogenic end member with a high 87Sr/86Sr ratio from water/aluminosilicate reactions in the rocks and/or meteoric run-off from the old crystalline basement.
The evolution of the pore water δ18OV-SMOW and δD can be constrained from authigenic phases such as dolomite, chlorite and quartz, if both the formation temperature and the stable isotopic composition of these cements are known or can be assumed (Table 2). In the Barik Sandstone Member of the Ghaba Salt Basin early poikilotopic dolomite with all-liquid fluid inclusions and δ18OV-PDB values ranging from -9.1 to -11.3‰ are indicative of a pore water δ18OV-SMOW value of < -7.3‰ (Land, 1983). Later formed pore-lining chlorite found in residual pore space at the surface of detrital grains sets constraints for the deeper-burial conditions. Assuming temperatures consistent with the K-Ar age range in the gas-leg, e.g. 80-110°C, the corresponding equilibrium δ18OV-SMOW value for the formation water is -3.5 ± 1.8% (n=26) or -2.6 ± 1.9‰ (n=12) for the Barik Sandstone Member or the Miqrat Formation, respectively (Hillier et al., 1996). The following burial-diagenetic quartz cement with homogenization temperatures between 117 and 132°C and δ18OV-SMOW values ranging from 14.3 to 18.1‰ (Tables 2 and 3) reveals a formation water δ18OV-SMOW value of -2.0 ± 1.7‰ (n=10) or -4.5‰ (n=3) for the Barik Sandstone Member or the Miqrat Formation, respectively (Friedman and O’Neil, 1977). Finally, late-stage dolospar from the Barik Sandstone Member at the Mabrouk-Makarem High and in the Miqrat Formation with a Th interval of 123-142°C and a δ18OV-PDB range of -10.2 to -11.5‰ points to a formation water δ18OV-SMOW value of 2.2 ± 1.1‰ (Land, 1983) for these stratigraphic units and areas. In essence, the pore water δ18OV-SMOW value in the Barik Sandstone Member of the Ghaba Salt Basin increased from < -7.3‰ at ≤ 50°C (poikilotopic dolomite) to -3.5 ± 1.8‰ at 80-110°C (chlorite) to -2.0 ± 1.7‰ at 117-132°C (quartz) to -1.6 ± 0.8‰ at present. Veizer et al. (1999) demonstrated that the δ18OV-SMOW value for Early Paleozoic seawater was about 6 to 8‰ lighter than recent seawater. Thus, the calculated early diagenetic pore water is in the range of Early Paleozoic seawater, but addition of continental water cannot be ruled out. Late-stage dolospar found in the Miqrat Formation and in the Barik Sandstone Member at the Mabrouk-Makarem High infers a positive δ18OV-SMOW value for late-stage pore water in these stratigraphic units and areas.
Interpretation of chlorite δD is hampered by uncertainties in the fractionation factor αchlorite-water, the effect of the chemical composition on hydrogen isotope fractionation, and the possibility of hydrogen isotope exchange subsequently to chlorite formation (e.g. Masuda et al., 1992; Graham et al., 1987; Kyser and Kerrich, 1991). Assuming that these chlorites are in isotopic equilibrium with the pore water at formation and no re-equilibration occurred, then the currently available data suggest a fractionation effect of approximately -10‰ at 80-110°C (Figure 18 in Savin and Lee, 1988). The measured δD of -64 to -45‰ (-30‰ Barik field) in chlorites from the Saih Rawl field, therefore, require a pore fluid δD ranging between -55 and -35‰, which is significantly lighter than the present day value of -10‰ (Table 5). The direct involvement of hydrocarbons to form chlorite might be the explanation for these light δD values (Fisher and Boles, 1990), as hydrocarbons are characterized by light δD. Moreover, if Early Paleozoic seawater had a δ18OV-SMOW of -7‰, as proposed by Veizer et al. (1999), then a concomitant shift in the δD would predict a δD value of ~ -55‰ for seawater (Knauth and Beeunas, 1986).
The δ13CV-PDB signature of early diagenetic dolomite varies between -1.1 and -3.2‰ which is slightly depleted relative to Cambrian/Ordovician marine values (-0.1 to -1.4‰, Veizer et al., 1999). This points to an inorganic source related to continental waters. Burial-diagenetic dolomite (Table 2) is characterized in the Ghaba Salt Basin by a similar δ13CV-PDB value as early diagenetic dolomite, whereas in the Mabrouk-Makarem High the values are generally lighter in both the Barik Sandstone Member and the Miqrat Formation. These lower values observed in the Mabrouk-Makarem High suggest a regionally different uptake of CO2 generated by thermocatalythic and/or redox reactions of hydrocarbons and not a more continental derived water as fluid inclusions reveal a high temperature formation/recrystallization (Th > 100°C) of these dolomites. No δ13CV-PDB values exist from present day pore water.
The pore water deduced from anhydrite in a late stage fracture (Fahud Salt Basin) is characterized by high salinity, a 87Sr/86Sr-ratio of 0.7088 and a δ34SV-CDT of 24.1‰ indicating an intraformational origin of this water. A cross-formational origin from the evaporitic Ara Formation is unlikely (Schröder et al., 2004) based on the measured 87Sr/86Sr-ratio and the δ34SV-CDT.
In conclusion, soon after deposition, the pore water in the Barik Sandstone Member in the Ghaba Salt Basin was highly saline, depleted in δ13CV-PDB and enriched, i.e. more radiogenic, in the 87Sr/86Sr-ratio relative to Cambrian/Ordovician seawater. This points to an addition of saline continental waters during and/or soon after deposition. During burial the pore water evolved to a composition with a more positive δ18OV-SMOW and δD and a more radiogenic 87Sr/86Sr-ratio. These changes reflect mineral-pore water ± liquid hydrocarbon reactions, including hematite oxidation, dolomite/anhydrite dissolution/recrystallization and/or chlorite formation. An influx of lower-saline water from the surface/subsurface during the obduction of the Oman Mountains, as observed in the overlaying Al Khlata Formation (Juhász-Bodnár, 1999) might have occurred in the Barik Sandstone Member and the Miqrat Formation during quartz cementation, but the sparse fluid inclusion data are not conclusive about the exact timing. The few data from the Miqrat Formation suggest a similar pore water composition and evolution as in the Barik Sandstone Member with the exception of a positive δ18OV-SMOW value at late stage. In the Mabrouk-Makarem High area, the pore water was additionally influenced in both units by CO2 derived from hydrocarbons.
Impact of Burial, Diagenesis and Charge History on Reservoir Quality
Basin modeling indicates three major periods (Terken et al., 2001) of hydrocarbon generation from Ediacaran to Early Cambrian Huqf Supergroup source rocks: (1) during deposition of the Haima Supergroup (535-425 Ma); (2) during deposition of the the Akhdar Group (256-230 Ma); and (3) since deposition of the Aruma Group (< 90 Ma). Most of the earliest oil expelled from the Huqf Supergroup source rocks charged the western flank and the Miqrat Formation sandstone in the central area of the Ghaba Salt Basin, indicating long-distance migration from the Ghaba Salt Basin to the western flank and an effective seal capacity of the directly overlaying shaly Al Bashair Member throughout the Ghaba Salt Basin (Figure 18a).
The early diagenetic red-bed type alterations, e.g. mechanical infiltration of clay particles and hematite precipitation, had a major impact for the early burial history as the clay coatings delayed quartz precipitation and thus left the pore-space open for hydrocarbon charging. Only locally the pedogenic precipitation of dolocretes pervasively occluded the pore-space. In addition, the lack of carbonaceous detrital grains or instable bioclasts might be the reason that no carbonate cement was precipitated during this early burial stage. After an early phase of subsidence, a phase of uplift from Middle Devonian to Late Carboniferous occurred (Figure 3), a time interval which left no recognizable diagenetic imprint in the sediments. Renewed subsidence led to liquid hydrocarbon emplacement inducing precipitation of chlorite at the expense of early diagenetic clay coatings and hematite. This reaction preserved porosity, but the following replacement of this liquid hydrocarbon by gas/condensate was a period of compactional porosity loss in sandstones where the grain surfaces were mainly clay coated and with only little quartz cement. Thus, the timing of the oil charge relative to the diagenetic and burial history has major consequences for the reservoir properties. In the Fahud Salt Basin the early, pre-Carboniferous oil charge delayed diagenetic reactions but was converted by biodegradation upon Late Devonian to Carboniferous uplift to pore-filling bitumen, resulting in a dramatic downgrade of the reservoir quality in this area (Figures 7f, 14 and 18a). On the Eastern Flank and the Mabrouk-Makarem High, however, the early, pre-Carboniferous oil by-passed and left the pore-space open (Figure 18a). Unlike the Fahud Salt Basin area, the Ghaba Salt Basin is characterized by a post-Carboniferous hydrocarbon charge. The timing of this hydrocarbon charge is well-documented by K-Ar age dating of the chlorite precipitation and the redox-type of this reaction which implies the presence of hydrocarbons (Surdam et al., 1993). The Eastern Flank of the Ghaba Salt Basin, however, experienced since that time a progressive uplift and tilting with surface water infiltration and loss/biodegradation of all hydrocarbons (Figure 18b). The pore water evolution in the Ghaba Salt Basin, which is mainly controlled by mineral reactions, clearly documents that this surface water infiltration on the Eastern Flank did not reach the central area of the Ghaba Salt Basin (Figure 18b). Increase of subsidence in the Fahud Salt Basin since the Late Permian, e.g. since the opening of the Neo-Tethys and formation of a passive margin in North Oman, created a positive structure to the east, the Mabrouk-Makarem High, where hydrocarbons from the Fahud Salt Basin and the western flank of the Ghaba Salt Basin accumulated (Figure 18b).
Obduction of the Oman Mountains initiated remobilization and replacement of the liquid hydrocarbons by gas/condensate from the Fahud Salt Basin and from a mini-basin at the west-flank of the Ghaba Salt Basin towards the east into the Ghaba Salt Basin (Figure 18c). The lower-saline event detected in fluid inclusions within late-diagenetic quartz and the Tertiary liquid hydrocarbon charge of the overlying Haushi Group (Terken et al., 2001) both support the presence of migration pathways into (gas/condensate, low-saline fluid) and out (liquid hydrocarbons) of the Haima Supergroup during Late Cretaceous to Tertiary times, i.e. during the obduction of the Oman Mountains (Glennie et al., 1974). Pore lining-bitumen observed in the Ghaba Salt Basin (Figure 14) may have formed by this gas flushing of the oil charge and/or by thermal cracking of the oil. Thus, the post-Carboniferous oil charge was obviously early enough to inhibit/retard further compaction and pore occluding cementation. In addition, the greater burial depth of the Haima Supergroup in the Ghaba Salt Basin relative to the Fahud Salt Basin during the post-Carboniferous hydrocarbon charge as well as the replacement of the primary liquid hydrocarbon by gas/condensate prevented the formation of pore-filling bitumen as seen in wells from the Fahud Salt Basin (Figure 18a). Hence, the deep parts (> 5,000 m) of the Ghaba Salt Basin with a post-Carboniferous hydrocarbon charge are more prospective than shallow parts with an early charge, e.g. the Fahud Salt Basin, because of the absence of early pore-filling bitumen, the possibility to form pore-lining chlorite during post-Carboniferous liquid hydrocarbon charge (which preserves porosity and permeability by retarding quartz cementation) and the replacement by gas/condensate which prevented late-stage pyro-bitumen formation.
Integration of sedimentary facies, basin evolution, diagenesis and charge history of the Early Paleozoic Miqrat Formation and Barik Sandstone Member indicates that the key critical success factors for the Haima Supergroup gas play are:
(1) the depositional environment which constrains the net-sand distribution,
(2) compaction and depth-related diagenetic reactions, mainly precipitation of early dolomite and late quartz, which reduce reservoir porosity,
(3) post-Carboniferous hydrocarbon-related chlorite formation, which preserves primary porosity and permeability by inhibiting quartz cementation and thus prevents reservoir quality deterioration,
(4) regional differences of burial history and timing of the initial oil charge versus structuration/halokinesis of the Ara Group salt. Early charge of shallow reservoirs and subsequent biodegradation leads to plugging by bitumen and total loss of porosity, and
(5) the risk of no charge due to obstructed migration pathways as a result of salt downloading.
The importance of each of these factors is regionally controlled and thus also the resulting reservoir quality and charge potential. The general decrease of the net-sand content northwards in the Miqrat Formation and northeastwards parallel to the axis of the Ghaba Salt Basin in the Barik Sandstone Member, results in poorer reservoir properties northwards. In the Fahud Salt Basin biodegradation of Early Paleozoic oil charge causes a major loss of porosity by bitumen clogging, whereas on the Mabrouk-Makarem High and the Eastern Flank area of the Ghaba Salt Basin pre-Carboniferous oil by-passed and left the pore-space open. Post-Carboniferous hydrocarbon charge was trapped in the post-Late Permian formed Mabrouk-Makarem High structure, but on the Eastern Flank, Late Paleozoic tilting, uplift and surface water infiltration converted the oil charge to pore-filling bitumen. In the Central Graben area of the Ghaba Salt Basin early oil accumulated in the Miqrat Formation, below the regional seal of the Al Bashair Member but not in the Barik Sandstone Member where post-Carboniferous hydrocarbon charged structures of post Late Devonian age. Replacement of the oil charge towards shallower reservoirs, e.g. clastics of the Haushi Group, by gas/condensate was initiated by the obduction of the Oman Mountains in Late Cretaceous, which prevented the generation of pore occluding pyro-bitumen in the Central Graben area of the Ghaba Salt Basin.
Appendix: Material and Methods
A total of 35 and 125 sandstone samples from the Miqrat Formation and the Barik Sandstone Member, respectively, were taken from wells in the Barik, Mabrouk, Makarem, Saih Nihayda and Saih Rawl fields and from the Jaleel-1, Ghaba-1, and Ramlat Rawl-5 wells. The present day depth of these samples ranges from 4,356 m to 5,183 m for the Miqrat Formation and from 3,299 m to 4,808 m for those from the Barik Sandstone Member.
All samples were impregnated with blue-dyed epoxy resin before thin-section preparation. Petrographic analyses and quantitative determinations (400 points per thin-section) of the detrital and authigenic phases, porosity and bitumen were done on polished thin-sections stained for carbonates (Dickson, 1966).
Authigenic chlorite was studied in 4 and 16 samples from the Miqrat Formation and the Barik Sandstone Member, respectively. Samples were gently crushed and the 2-6 μm size fraction was separated in Atterberg settling tubes. A high-gradient magnetic separation device (HGMS) developed at the Geological Institute in Bern (Hillier et al., 1996) was employed to purify the concentrates from variable amounts of quartz, K-feldspar, albite, dolomite, anhydrite and illite. After 3 to 5 passes per sample, the purity of the concentrates was > 90% and in most cases > 95% pure chlorite, the remainder being traces of quartz and feldspar. The chemical composition of chlorite was determined by X-Ray Diffraction Analysis (XRD) on the basis of the ideal chlorite formula (Bailey, 1984)
The x and y parameters were computed based on the relationships of Brindley (1961)
where d(001) denotes the d value of the first basal chlorite spacing (in Å) and b is the b parameter (in Å) of the chlorite unit cell. The d(001) value was obtained from the (004) chlorite spacing calibrated against the (100) quartz peak and the b parameter from the (060) chlorite peak calibrated against the (211) quartz peak.
For δD and δ18O analyses all 20 HGMS concentrates were used and analyses were performed at the Scottish Universities Research and Reactor Centre (SURRC) in Glasgow. Oxygen was liberated by reaction with ClF3, purified, reduced to CO2, (Fallick et al., 1993) and measured with a VG-SIRA 10 mass spectrometer. Hydrogen was extracted by heating the samples under vacuum, converting the released water to hydrogen by reaction with hot uranium (Fallick et al., 1993) and then analysed using a VG Micromass 602B mass spectrometer. The δD and δ18O isotope ratios are quoted relative to the Vienna Standard Mean Ocean Water (V-SMOW) and the analytical precision (2σ) based on measurements of standard material was estimated as ±10‰ for δD (NIST SRM 30) and ± 0.4‰ for δ18O (NIST SRM 28).
Quartz overgrowths were separated by the method of Lee and Savin (1985) and isolation of the three size fractions was performed as detailed in Brint et al. (1991) at SURRC. SEM analyses of the <53 μm, 53-85 μm and > 85 μm size-fractions showed a purity of almost 100%, > 50% and < 10%, respectively, of authigenic quartz. The δ18O of quartz was measured on a VG-SIRA 10 mass spectrometer. Results are quoted relative to V-SMOW and isotopic reproducibility (2σ) of the standard material NIST SRM 28 is ± 0.4‰.
Carbon and oxygen stable isotope analysis of dolomite was performed either off-line by reacting the powdered sample (Fe-dolomite) in 100% H3PO4 at 50°C for 5 hours or by reacting the sample (dolomite) in an on-line automated extraction system in 100% H3PO4 at 90°C. Isotopic ratios of the released CO2 gas was measured on a VG Prism II ratio mass spectrometer, and they are quoted relative to the Vienna Pee-Dee Belemnite Standard (V-PDB). The δ18O was corrected for phosphoric acid fractionation effects. Isotopic reproducibility (2σ) of standard material is better than 0.1‰ for δ13C and 0.2‰ for δ18O.
For δ34S analysis, samples containing anhydrite cement were crushed and anhydrite was concentrated by sieving in ethanol. Sulfur isotope analyses were performed at SURRC. Anhydrite was converted to pure BaSO4 as described by Sullivan et al. (1994), and δ34S was measured on SO2 gas using an Isospec 44 double collector mass spectrometer (Coleman and Moore, 1978). Isotopic reproducibility of the standard material NIST SRM 127 is better than 0.4‰ (2σ), and results are quoted relative to the Canyon Diablo Troilite (V-CDT) standard.
Strontium isotope analysis was preformed on dolomite and anhydrite cement. The crushed rock samples were repeatedly washed in MiliQ water under ultrasonic agitation. For dolomite a 15 minute cold leach in 2N HCl was applied. Samples containing anhydrite were dissolved in hot double distilled water to extract Sr of anhydrite. Strontium isotope analysis including measurements of the strontium and rubidium concentrations were performed by isotope dilution at the Department of Isotope Geology, University of Bern using a > 99.9% 84Sr spike on a 5 collector VG sector instrument using the dynamic multicollector mode. Rb concentrations were not determined for anhydrite as this mineral usually excludes Rb from its crystal lattice (Holser, 1979). Repeated analyses of NIST SRM 987 during the measurement period yielded a mean value of 0.710256 ± 0.000030 (2σ, N=15). Extensive leaching of clay minerals occurred in some samples during acid treatment. This effect is clearly observed in five samples with 87Rb/86Sr > 1, where a covariant trend exists between the 87Rb/86Sr ratio and the illite/dolomite ratio.
Conventional K-Ar geochronological dating was performed by FM Consultants Ltd. on clay-grade (0.5-4 μm) chlorite/illite intergrowths. The sandstone samples were carefully reduced to fragments of < 20–12 cemented detrital sand grains and then disaggregated by ultrasonic vibration into the clay fraction and detrital grains. XRD analysis was used to check on the progress of the disaggregation procedure, which was continued until the dating chlorite/illite intergrowths contained a minimum of K-feldspar and plagioclase. Triplicate conventional K-Ar dating with an error of < 6.2% (2σ, single analysis) were preformed on 13 concentrates.
Fluid inclusions suitable for microthermometry were found in quartz and dolomite cements from the Barik Sandstone Member and the Miqrat Formation in the Ghaba and Fahud Salt Basins and the Mabrouk-Makarem High area (Figure 2). Doubly-polished, 100 μm thick rock wafers were prepared for microthermometric analyses of primary and pseudo-secondary (according to Roedder, 1984) single and two-phase, liquid-rich aqueous inclusions with a size of 2.5 to 5 μm. A Linkham semi-automatic, gas-flow freezing-heating stage, calibrated against known melting-point standards, was used. No pressure correction was applied (Burley et al., 1989), and the measured homogenization temperatures (Th) were considered as minimum trapping temperatures of the inclusions. Th measurements were reproducible within an accuracy of ± 1°C, whereas for final ice melting temperature (Tm(ice)), the accuracy was ± 0.25°C.
The authors thank the Ministry of Oil and Gas of the Sultanate of Oman and Petroleum Development Oman for their support and permission to publish the results of this study. The detailed and constructive reviews by two anonymous reviewers are greatly appreciated.
ABOUT THE AUTHORS
Karl Ramseyer is Professor at the Institute of Geological Sciences at the University of Bern from which he was awarded his PhD in Geology in 1983. His main areas of interest are diagenesis and the application of cathodoluminescence in Geology. Since 1985 Karl has been working in co-operation with Petroleum Development Oman on clastic diagenesis of the major oil and gas producing strata in Oman.
Joachim E. Amthor received a Diploma (MSc equivalent) in Geology from the University of Würzburg, Germany, in 1986, and a PhD from City University of New York Graduate School in 1990. After two years as a post-doctoral fellow at McGill University, Montreal, Joachim joined Royal Dutch Shell in 1992 as a Research Geologist. In 1996 he was posted to Petroleum Development Oman (PDO), where he worked as a Senior Geologist in the Frontier Exploration Asset Team mainly on the Precambrian Intrasalt carbonate discoveries. In 2001, Joachim joined the Northern Oil Directorate of PDO as a Senior Production Geologist, responsible for geological support of Petroleum Engineering studies of Lower Cretaceous carbonate fields in North Oman. Joachim has published numerous papers in international journals. He is a recipient of the 1994 Medal of Merit of the Canadian Society of Petroleum Geologists for the best paper published on a subject related to Canadian petroleum geology, and of the 1998 George C. Matson Award of the American Association of Petroleum Geologists for the best oral technical presentation at the Annual Meeting.
Christoph Spötl is currently Professor at the University of Innsbruck from which he received his MS in Geology in 1987. He received a PhD degree from the University of Bern in 1991. His main research interests include sedimentary geochemistry and diagenesis and, more recently, paleoenvironmental studies and Quaternary science.
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. In close cooperation with the Geochemistry group he modeled and mapped the petroleum systems of Oman. Since November 1999, Jos has been a Senior Production Geologist for the Nederlandse Aardolie Maatschappij in The Netherlands. He received an MSc in Geology/Sedimentology from the University of Utrecht in 1982.
Albert Matter is Professor Emeritus at the University of Bern from which he received a PhD in Geology in 1964. His areas of interest include sedimentology, groundwater hydrogeochemistry and clastic diagenesis. Since 1967 Albert has been working in Oman, partly in co-operation with Petroleum Development Oman. Currently he is involved in sedimentological studies in Oman and in a paleoclimate project which aims to develop paleoclimate records of variation in Monsoon rainfall in Oman, Yemen and Saudi Arabia during the Pleistocene and Holocene.
Marietta Vroon-ten Hove joined Royal Dutch Shell in 1989 after receiving her MSc in Geology from Utrecht University in 1988. During her first two assignments as a Research Geologist in The Netherlands and as Team Geologist in Shell Exploration and Development Madagascar, she developed an interest in integrated field studies; in particular, reservoir sedimentology and the integration with seismic data. In 1994, Marietta was posted to Petroleum Development Oman, where she worked as a Reservoir Geologist in the Exploration Laboratory. She carried out seismo-stratigraphic interpretation and regional mapping of the Pre-Salt Huqf, and took part in the development of predictive sedimentological/diagenetic models for the Haima gas reservoirs. From 1997 till present, she has been working in various jobs within Shell in The Netherlands. From an initial emphasis on exploration scale studies (addressing the regional hydrocarbon habitat of the South China Sea, the evaluation of Morocco Deepwater Acreage), she moved towards the realm of production geology and reservoir modeling. During 2001-2002, Marietta joined the Shell China Team to establish reservoir models and field development plans for gas fields in the Ordos and Tarim basins. Currently, she is working as the Senior Geologist in EP-Solutions on development planning and operational support for the Pearl Gas-to-Liquids project.
Jean R.F. Borgomano received his MS degree in Geology from the University of Paris VI in 1981 and a PhD in Carbonate Sedimentology from the University of Provence in 1987. After working for one year as Well-site Geologist with Exlog, he joined Shell International BV in The Netherlands as a Sedimentologist. Jean then worked four years in Oman as a Sedimentologist and 5 years in Norway as an Exploration Geologist. In 1999 he was Project Leader in a multidisciplinary team working on a carbonate reservoir at Shell EP Technology in The Netherlands. Since 2003 Jean has been Professor of Geology and Director of the Laboratory of Sedimentology and Paleontology at the University of Provence. His current scientific interest is the modeling of carbonate systems and reservoirs.