Exploration history of the Ara intrasalt carbonate stringers in the South Oman Salt Basin

Hydrocarbon exploration in South Oman began slowly after the first operating licence was awarded to Petroleum Development Oman and Dhofar in 1937. Activities within the South Oman Salt Basin (SOSB) proper (Figure 1), however, did not start until 1953 when the acreage was acquired by Dhofar Cities Service. All of the wells drilled in this basin at that time targeted the presalt section of the Huqf Supergroup (Figure 2), some of which did encounter Ara stringers. By 1969, the Dhofar Cities Service acreage was acquired by PDO, who continued intermittently exploring for presalt objectives in the SOSB (Figure 3). While Ara intrasalt stringer exploration has figured prominently in PDO’s exploration annual activity plan since 1998, the first intrasalt discovery was made in 1976. Nasir-1, which was drilled to test for moveable hydrocarbons in the presalt Buah Formation, unexpectedly penetrated a highly overpressured carbonate stringer after drilling 334 m in the Ara salt (Figure 4). A kick was taken at the top of the stringer and 40 bbls of 27° degrees API sour crude were recovered. The 46-m-thick stringer in Nasir-1 consisted of coarse crystalline-sucrosic, generally vuggy dolomite, with subordinate thin interbeds of dolomite, limestone, anhydrite and silty shales (Figure 4). Log evaluation indicated that the upper part of this carbonate stringer was oil-bearing and 36 m of net oil pay was evaluated. When tested, the well flowed over 6,000 bbls/d of oil. This accidental discovery marked the start of stringer exploration in the SOSB.

The intent of this paper is to chronicle the exploration history of the Ara intrasalt stringers in the SOSB. This Ara exploration history spans a period of 27 years (Figure 3), and can be divided into three phases. To properly chronicle this history, a brief summary of the Athel exploration campaign has also been included.

The SOSB is part of a series of NE-SW trending restricted basins that include the Al Ghabah and the Fahud Salt Basins (Figure 1). The western margin of this basin is delineated by a structurally complex transpressional deformation front (Immerz et al., 2000), while its eastern margin is characterized by onlap and thinning of basin strata onto a structural high located parallel to the present coast line of Oman. The Ara evaporites and interbedded carbonates and silicilyte form the Ara Group, which is part of the Neoproterozoic to Early Cambrian Huqf Supergroup (Figure 2) (Gorin et al., 1982; Hughes Clarke, 1988; Burns and Matter, 1993; Brasier et al., 2000; Amthor et al., 2003). The Huqf Supergroup overlies crystalline basement and consists, from bottom to top, of the Abu Mahara, Nafun and Ara Groups.

Six lithostratigraphic units are identified within the Huqf Supergroup (Figure 2). These are (in stratigraphic order): Ghadir Manqil (siliciclastic), Masirah Bay (siliciclastic), Khufai (carbonates), Shuram (siliciclastic), Buah (carbonate), and the thick carbonate and evaporite successions of the Ara Group. Early chronostratigraphic interpretations placed the entire Ara Group in the terminal Proterozoic (Conway Morris et al., 1990; Burns and Matter, 1993; Kaufman and Knoll, 1995; Saylor et al., 1998; Braiser et al., 2000; McCarron, 2000). Recent work involving the integration of new carbon isotopic data, biostratigraphy and U-Pb geochronology has placed the upper part of the Ara in the Early Cambrian (Amthor et al., 2003; Al-Husseini et al., 2003). Recent work has also shown that the basin experienced rapid subsidence during Ara times allowing for the deposition of the thick inter-layered carbonates and evaporite strata of the Ara Group (Amthor, 2000; Grotzinger et al., 2002; Al-Siyabi and Grotzinger 2002; Cozzi and Al-Siyabi, 2004). The Ara salt was subsequently deformed halokinetically as a result of early Palaeozoic sedimentation resulting in a wide array of salt tectonic features (Al-Marjeby and Nash, 1986; Heward, 1990; Al-Barwani et al., 2002). Favourable conditions were created for the generation, trapping and long-term preservation of hydrocarbons within the Ara Group.

The hydrocarbon-bearing Ara carbonate stringers represent isolated carbonate platforms that consist of at least six third-order cycles of carbonate/evaporite sedimentation in a tectonically active basin (Figure 2). Each cycle contains several isolated carbonate platforms formed during transgressive to highstand accommodation conditions (Grotzinger and Amthor, 2002). The reservoirs consist of porous dolomites stratigraphically trapped in salt at depths of 3–5 km, and are commonly overpressured (Al Hashimi et al., 2000). The play is particularly complex with respect to reservoir quality prediction, hydrocarbon charge, and seismic imaging. The Neoproterozoic age of the mostly shallow-water carbonates poses a challenge both in understanding the origin and spatial distribution of the various lithofacies, their correlations and in building predictive sets of reservoir models. The vuggy and fractured dolomite reservoirs are part of several evaporite-carbonate cycles deposited in a restricted platform setting. Early phases of salt movement influenced carbonate sedimentation and dolomitization, creating both reservoir and source rock facies and structural development that later governed oil migration and entrapment. The thick halite sequences provide the seal for the intra-formational trapping of hydrocarbons. The intrasalt carbonates were previously regarded as a self-charging hydrocarbon system (Frewin et al., 2000), containing carbonate source rocks in close proximity or even within the dolomite reservoirs (Amthor and Al Zadjali, 2000). Recent geochemical work, however, suggests a contribution of presalt source rocks in some stringers.

Since 1997, PDO has made several oil and gas discoveries in the Harweel area in the southern part of the SOSB (Reinhardt et al., 1998; Reinhardt et al., 1999; Reinhardt et al., 2000, 2001; Shuster, 2003). In addition, intrasalt sedimentary bodies have also been recognized in the Al Ghabah and Fahud Salt Basins. The prospectivity of the intrasalt in these basins has come into focus following the documentation of stringer-like carbonate facies in the surface-piercing salt diapirs in the Al Ghabah Salt Basin (Peters et al., 2003, Al-Balushi, 2005).

The Nasir-1 production performance highlighted the exploration potential of the Ara intrasalt stringers in the SOSB. As a result, an extensive 2-D seismic grid was acquired over the greater Marmul-Nasir area in late 1976 and early 1977. Screening of the newly acquired seismic quickly focused the evaluation efforts on two areas where abundant stringer slabs occurred: Dhahaban and Birba (Figure 5). By early 1977, an exploration drilling campaign followed with the Ara stringers as the primary exploration objective. The first well drilled in this campaign was Birba-1 (spudded December 13, 1977) with the objective of testing for moveable hydrocarbons in two dolomite stringers within the Ara salt. Stringer-1 was found oil-bearing, and flowed over 9,000 bbls/d of 27° API oil (Figure 6). This result, combined with the earlier Nasir-1 production performances, launched the first intrasalt exploration phase.

Exploration during this first phase was based on a simple tectonostratigraphic model that linked the presence of abundant stringer slabs to areas where basement-related highs occurred. Pre-existing basement structural highs, both in Birba and Dhahaban areas, were believed to have facilitated through their continuing tectonic activity the growth of carbonates during Ara times. At the regional scale, the Birba and Dhahaban stringers were considered to be the continuation of the same depositional system (Figure 7). This model, which was constrained by a handful of penetrations, placed the Birba carbonates on the seaward part of this system, while the Dhahaban stringers represented the landward part of this environment. The seal for these porous and permeable carbonate deposits was provided by the surrounding Ara salt.

Activities in the Greater Birba Area continued after the Birba-1 discovery in the form of exploratory appraisal drilling and green-field exploration. Exploratory appraisal activities focused on the appraisal of the Birba field. This effort lasted from 1978–1983, and involved the drilling of five wells (Figure 8). Green-field exploration, on the other hand, involved the drilling of a number of outstep wells to delineate the regional extent of Stringer-1 within the Greater Birba area (Figure 8). Reservoir presence, outside the Birba field, was confirmed with the drilling of Birba South-1 (1979) and Birba North-1 (1979). Both penetrations found the objective stringer gas-bearing. By then, the geographic extent of the prolific Stringer-1 was mapped over a 100 sq km area. The exploration strategy, therefore, focused on delineating the reservoir fairway of this stringer over that area.

As a consequence, Omraan-1 (1980) was drilled northwest of the Birba field, but in a down-dip direction. The well struck oil in a much younger cycle (Stringer-0). The drive to unlock the hydrocarbon potential of Stringer-1, in the Greater Birba area, continued with the drilling of Amjad-1 (1981). The well, unfortunately, found the objective stringer water-bearing. As part of the same effort, Durra-1 (1982) was drilled the following year in a down-flank position from the Birba-Nasir-Amjad anticlinal ridge. This well, unexpectedly, encountered 31 m of net pay in an older stringer, later called Stringer-2. Upon testing, the slab flowed over 1,700 bbls/d of 35.9^o API oil. The Durra production test had demonstrated, for the first time, the feasibility of commercial flow from this older Ara cycle. A second Stringer-2 discovery was made the following year with the drilling of Kaukab-1 (1983). By the end of 1983 and as a consequence of this drilling campaign, the structural configuration and the distribution of Stringers-1 and 2 were fairly constrained in the Greater Birba area (Figure 9). An improved understanding of the depositional system was also emerging. Detailed core investigations revealed that these carbonates were deposited in very shallow, supratidal to intertidal settings, during periods of basin-wide transgressions of marine water with normal salinity. Reservoir facies consisted of locally fractured, partly vuggy crystalline sucrosic dolomites interbedded with dolomitic limestone, anhydrite and argillaceous siltstones. The interlayered Ara salts were deposited from hypersaline water when the basin became restricted. The hydrocarbon-bearing stringers were believed to be self-charged as evidenced by the occurrence of organic-rich intervals interbeded with dolomites in wells such as Nasir-1. These organic-rich intervals remained in communication with their laterally equivalent, shallow-water dolomite beds, to provide local charge by lateral migration.

Exploration outside the Birba area did not start until 1980 with the drilling of Dhahaban South-1 (Figure 10). Located 95 km southwest of the Birba field, the well represented a strategic test for the stringer play outside the Birba proven domain. The well (spudded on March 23, 1980) was drilled to test a stringer cycle positioned very close to the base of the salt (Figure 7). A 54-m-thick dolomite stringer was encountered with 35 m of net pay and an average porosity of 10%. A short production test flowed 29^o API oil at rates greater than 3,600 bbls/d. This successful outcome led to the drilling of five wells in the Dhahaban South area during the period from 1980–1986 (Figure 10). Most of the drilling activity was geared towards appraising the Dhahaban South structure, which was mapped over a 150 sq km area. This exploratory appraisal effort involved the drilling of three wells, but all failed to find moveable hydrocarbons in this basal Ara Stringer. Green-field exploration in the Dhahaban area started in 1982 with the drilling of the first outstep well, Watawb-1 (Figure 10). The well, which is located 11 km southwest of the discovery well Dhahaban South-1, encountered immobile oil in the basal Ara objective. Intrasalt exploration efforts in the Dhahaban area were halted after the Watawb-1 well results. Activities resumed three years later with the drilling of the Bakhur-1 (1986), but this well was also dry.

Despite the success achieved by the Birba-Dhahaban exploration phase, the stringer play proved to be complicated. Limited knowledge of stringer depositional systems and diagenetic history hampered reservoir quality prediction. Explaining production behaviour was next to impossible. In addition, seismic mapping of the Ara stringers turned out to be a major challenge, partly because of seismic quality, but mostly due to limited coverage over the SOSB. By 1981, the intrasalt exploration campaign was struggling. Success in the Birba area was limited to the drilling of appraisal wells and no discoveries had been made in the Dhahaban area since the drilling of Dhahaban South-1. After the disappointing result of Bakhur-1, Ara exploration activities were halted and the play became dormant.

The drive in the late 1980s to estimate the gas potential in PDO’s concession area brought the Huqf Supergroup, in the SOSB, back to the forefront of exploration strategy. Since most of the gas potential in South Oman was believed to be locked in the deep Huqf, interest in exploration opportunities in that part of the stratigraphy was revived. As a consequence, a review of these opportunities was carried out during the second half of 1988. The Ara stringer play was one of four plays covered by this review. Because of the existence of a better regional understanding and demonstrated success in the past, the review concluded that the Ara intrasalt play had the highest chance of success both for oil and gas exploration. The second phase of stringer exploration was therefore initiated.

While the basic elements of the play concept did not change since the last drilling campaign, the depth of knowledge about the depositional system had significantly improved. Most of the improved regional understanding of the carbonate stringers was the result of work done by B.W. Mattes and L. Gaarenstroom during the period 1982–1984, a summary of which was later published by Mattes and Conway-Morris in 1990. Based on this work, the Ara Group was divided into a minimum of five basin-wide cycles (Figure 11). Each of these cycles consisted of carbonate, evaporite, and clastic sedimentary units. The carbonates in each of these cycles were deposited in distinct facies belts that were controlled by bathymetry. Reservoir rocks were recognized as shelf grainstones, and within small bioherms constructed by frame-building algae with high initial porosities. At the same time, source rock-bearing intervals were deposited as sapropelic basinal sediments in deep, density-stratified troughs. During periods of basin restriction, the SOSB was isolated from the open ocean and thick units of sulphate, rock and potassium salts precipitated, which later provided seals for the Ara reservoirs.

With that background information, a regional evaluation of the SOSB was initiated in 1988. Three prospective areas emerged where the potential of the Ara play was thought to be significant (Figure 12). The area located between the Dhahaban and Birba proven domains was one of these prospective parts where a large concentration of stringer slabs occurred. Additional prospectivity was also recognized in the Birba area, particularly in the area southwest of the Nasir-1 discovery. Intrasalt prospects were also recognized to the northeast of Birba, in an area where no stringer prospects had previously been mapped. The exploration campaign encompassed the assessment of the play potential in all of these areas. Success in any of these localities could potentially establish the Ara stringers as a play that could significantly contribute to annual reserves additions thereby justifying the drilling of two deep stringer wells per year, for three to four years to come. As a result, three strategic opportunities were identified for maturation to drilling stage. Furthermore, two 3-D surveys were slotted into the 1989 seismic acquisition sequence to further mature two of these drilling opportunities.

The first well drilled as a result of this evaluation effort was Al Noor-1 (1989). The well was a strategic test of the Ara stringers in an area previously interpreted not to contain any stringers (Figure 12). The well encountered two hydrocarbon-bearing, high-pressured carbonate stringers and a very thick interval (505 m) of siliceous ooze and source rock that was interpreted to belong to the Athel Formation. While previous Athel penetrations were known from the Eastern Flank, Al Noor-1 represented the first penetration of this formation in the SOSB encased in the Ara salt. Testing of the two stringers in the well yielded high initial rates of light oil and gas followed by a rapid decrease in flow rates. Fifty meters of net pay, on the other hand, were evaluated in the Athel Formation. After acidization, a stable rate of 188 bbls/d of volatile oil was achieved with rapid buildup to the original pressures after closing in. The unexpected penetration of the Athel Formation, and the subsequent encouraging production performance, initiated an effort to reassess the stratigraphy of the Huqf Supergroup in the SOSB. Particular emphasis was placed on the prospectivity of the Athel Formation and its potential as a deep oil play in South Oman.

The second well drilled as part of this stringer drilling campaign was Hawmyat-1 (1990, Figure 12). The prospect was recognized as one of the larger more promising opportunities in the area located between the Birba and Dhahaban proven domains. The prospect was initially mapped on poor-quality 2-D seismic data, which impeded the proper imaging of the crestal area. To minimize the risk of drilling an expensive deep well based on unsatisfactory seismic, the Hawmyat 3-D seismic grid was acquired for better structural resolution of the objective stringer. Moveable oil, although heavier than expected, was proven to be present in both stringers that the well penetrated. In both stringers, sustained flow was not possible during testing because of poor reservoir development. Flow from the lower part of the upper stringer was further hampered by the presence of salt in the pore space. Shamah-1 (1990, Figure 12) was the third and last well drilled as part of this campaign. The well penetrated three stringers, but failed to encounter any moveable hydrocarbons.

The short-lived 1988–1990 evaluation and subsequent drilling campaign, negatively impacted the prospectivity of the Ara intrasalt stringers play in the SOSB. The results of both the Hawmyat-1 and Shamah-1 wells illustrated the complexity of the play, particularly with regard to predicting reservoir quality. In addition, the results of the Hawmyat-1 well highlighted that the deterioration in reservoir quality in the stringers was not only a function of facies variability, but could also result from secondary parameters such as salt plugging. Despite the lack of success in finding commercially producible stringers, the campaign highlighted the importance of using 3-D seismic data. The accidental penetration of the Athel Formation in Al Noor-1 and its subsequent production performance, necessitated the re-evaluation of the Huqf stratigraphy in the SOSB. In fact, the results of the Al Noor-1 well launched the Athel as an exploration play that would dominate deep oil drilling in SOSB until 1997.

The discovery of the Athel reservoir in Al Noor-1 opened a new play in the SOSB. Although initially evaluated as non-reservoir shales and siltstones, the Athel was later re-evaluated as a hydrocarbon-bearing, porous, siliceous reservoir defined as a silicilyite. A total of 104 m were perforated over three zones producing a commingled rate of 300 bbls/d of light oil and associated gas. This new deep (4–5 km) reservoir type was characterised by the occurrence of light (48° API) but sour oil in a porous reservoir (up to 30%), within a very low permeability matrix (0.02 mD) at high reservoir pressures (19.8 kPa/m) (Amthor et al., 1998; Amthor et al., 1999; Amthor et al., 2005). To further investigate whether better flow rates could be attained from this unit, the exploratory appraisal well Al Noor-2 was drilled in 1992. A barefoot production test on an open-hole section produced an initial flow rate of 314 bbls/d. After drilling two sidetracks, the flow rate increased to over 600 bbls/d.

The production performance of Al Noor-2 demonstrated that economic production from the Athel was feasible and marked the start of the Athel exploration campaign in the SOSB. An extensive seismic review was initiated in late 1993 to evaluate intrasalt reflectivity across the entire SOSB resulting in the identification of more than thirty Al Noor “look-alikes” (Figure 13). With this prospect and lead inventory, the upside potential of the Athel play was recognized to be an order of magnitude greater than anything else that existed in PDO’s exploration portfolio at that time. The biggest challenge posed to the Exploration Unit was to conclusively evaluate the potential of this play in the shortest possible time. A 2-year Athel exploration drilling strategy was therefore devised with the following objectives: (1) assess the upside potential of the play in the Greater Al Noor area; (2) improve production rates from the Athel reservoir; and (3) test the prospectivity of the Athel outside the Al Noor proven area.

Full-scale exploratory appraisal drilling started on the Al Noor structure in 1995 with two objectives. The first was to accurately assess the in-place volumes in the Al Noor structure, and the second was to experiment with various drilling and production technologies to improve flow rates from the Athel reservoir. In addition to the drilling of multilateral legs in Al Noor-2, two additional technology trials were attempted in two appraisal wells drilled in the Al Noor field. The first involved a massive freshwater squeeze in Al Noor-3 (1995) intended to remove salt from pore space. This technology did not result in a significant improvement in production rates. The second was massive hydraulic fracturing, attempted in Al Noor-4, which resulted in improved flow rates of over 600 bbls/d.

In the meantime, continued exploration in the vicinity of Al Noor structure resulted in another Athel discovery in 1995. Al Shomou-1 was drilled to test an independent Athel structural closure some 9 km to the southwest of Al Noor-1 (Figure 13). The well encountered 305 m of net pay in the Athel with an average porosity of 24%. An initial production test yielded disappointing rates of 314 bbls/d. The well was stimulated with fresh water, which improved the production rates to 533 bbls/d. Subsequent exploratory appraisal activity in Al Shomou structure involved the drilling of three more wells (Al Shomou-2, 3, and 4) in the period 1996–1998. Two of these wells, Al Shomou-2 and 3, were drilled as sub-horizontal, long-reach wells downflank to increase flow rates by maximizing the drain-hole length. This technology provided limited production improvement. At the same time, attempts to expand the Athel silicilyte play within the Greater Al Noor area continued, but without success. Al Fajr-1 (Figure 13) and Al Kanz-1 (Figure 14) were two wells drilled in the area in 1996 that did not find any Athel silicilyte.

By 1995, an accelerated Athel drilling campaign was underway; aimed at rapidly defining the extent and prospectivity of the potentially very prolific and extensive Athel silicilyte. Dasimi-1 (spudded July 22, 1995, Figures 13) was a considerable outstep in that campaign. Located southwest of the Birba-Dhahaban high trend, Dasimi-1 was drilled to provide crucial data on reservoir development, source rock maturity and conversion, and oil-quality distribution within the Athel play domain. Instead of finding the silicilyte, the well encountered intrasalt carbonate stringers with marginal pay. Al Mesbah-1 (1995, Figure 13) was another outstep drilled to test an imbricated stack of overpressured Athel silicilyte slabs in a closure located some 45 km northeast of Al Noor-1. Again, no silicilyte was encountered in this well. The intrasalt reflections interpreted as Athel consisted, instead, of finegrained clastics.

Exploratory efforts outside the Al Noor area continued in 1996 with the drilling of Marmul NW-7 (Figure 14). The well, which was situated in an area that was largely untested at the time, penetrated a 207-m-thick package of hydrocarbon-bearing Athel silicilyte with no observed oil/water contact. Produceability from this slab was negatively affected by the presence of heavy oil at hydrostatic pressures. Nonetheless, this Athel oil discovery proved that the silicilyte reservoirs of Al Noor and Al Shomou are not unique. Makhzoun-1 was therefore drilled as a follow-up (Figure 14). This well found the objective silicilyte water-bearing. By 1997, Athel exploration was reduced to the drilling of two outstep wells. The first was Mazraq South-1, which failed to find any Athel (Figure 14). The second well was Katheer Deep-1, which was drilled to assess the prospectivity of the Athel in the northern part of SOSB (Figure 13). The reflective interval, originally interpreted as the Athel, consisted instead of six carbonate and anhydrite stringers. A much thinner and hydrostatically pressured Athel was encountered.

The 1989–1997 Athel exploratory appraisal campaign led to the discovery of two oil fields with over 2.3 billion barrels of oil-in-place. Booked reserves from the Al Noor field structure alone were estimated at 94 million barrels (O’Dell, 1997). These reserves were deemed sufficient to develop the field, which was brought on stream in 2000. The Athel silicilyte play, however, proved to be complex with respect to seismic recognition, and production behavior (Lake et al., 1998; Hoogendijk et al., 2000). The penetration of alternating carbonate, anhydrite and siltstone sequences in outstep wells, such as Dasimi-1, Al Mesbah-1, and Al Fajr-1 (Figure 13), highlighted the magnitude of the geophysical challenge posed by this play. It also shattered the hypothesis that the silicilytes were deposited as a thick regionally extensive sheet. Instead, Athel deposition was probably confined to basins between Buah topographic highs (Figure 14) (Amthor et al., 2005). Furthermore, improving well productivity remained a challenge. To improve flow rates from Athel wells, four technology trials were attempted. While water squeeze, multi-lateral drain holes, and extended-reach horizontal drilling marginally improved production performance, dramatic improvement was achieved only by massive hydraulic fracturing technology (Figure 15) (Wong et al., 1988). None of these technologies had previously been attempted at these depths and pressures in the Middle East. Despite all of these efforts, the wells drilled outside the Al Noor and Al Shomou area were either non-commercial or failed to find silicilyte. By 1997, the Athel play was struggling.

By late 1996, the evaluation part of PDO’s Exploration Unit was reorganized into theme-based integrated, multidisciplinary teams focused on the main plays of Oman. One of these teams, the Stringer Theme Team, was tasked to fully assess the remaining upside potential of the stringer play (Reinhardt et al., 2000, Hoogendijk et al., 2000, Reinhardt, 2001). The team quickly focused their efforts on the under-explored area located between the Birba and Dhahaban South discoveries, where the integration of well correlations, existing core data and regional seismic mapping indicated a potentially productive carbonate platform margin.

The Harweel Deep prospect was chosen as the first strategic test of the play potential in this part of the SOSB because of its large size, volumetric potential and good definition on 3-D seismic (Figures 16 and 17). Success in Harweel Deep would open-up further exploration and appraisal opportunities in the greater Harweel area. Harweel Deep-1 was spudded on April 24, 1997, to test for moveable hydrocarbons in a thick sequence of intrasalt stringers. After drilling 3,200 m within the Ara salt, four overpressured (21.6 kPa/m), oil-bearing carbonate stringers were encountered with total gross thickness of 465 m (Figure 16). Of the four, only Stringer-2 was successfully tested yielding a stable flow rate of 1,633 bbls/d. This deep oil discovery revitalized the stringer play in this new fairway and marked the start of a stringer exploration campaign that dominates deep oil drilling to the present day.

After discovering oil in Harweel Deep-1, stringer evaluation efforts in the SOSB became focused on maturing follow-up opportunities to drilling stage, and developing stringer leads and prospects in this area. As a result, two more Stringer-2 discoveries were made in Sarmad-1 (1998) and Ghafeer-1 (1998) (Figure 17). From then on, the exploration strategy for this cluster of fields focused on identifying and proving-up additional reserves to improve the commerciality of future development options. Exploratory appraisal activities on the Sarmad and Ghafeer fields commenced immediately. Follow-up opportunities to the Sarmad and Ghafeer discoveries were pursued as early as 1999. As a result, another Stringer-2 discovery was made with the drilling of Sakhyia-1 (1999, Figure 17), where over 6,000 bbls/d of stable flow-rate was attained. Flow was also established from an older slab (5,338 bbls/d), later named Stringer-4. These continuing Stringer-2 discoveries made since the start of this campaign were only interupted by the drilling of Ambrah-1 (1999), which found a repeated Stringer-2 tight (Figure 17). It was also around this time that the terminology for the various stringer cycles was changed to reflect their newly recognized stratigraphic arrangements (Figure 18).

The production performance of the A2C (previously Stringer-4) in Sakhiya-1, combined with favorable reservoir properties, encountered in other A2C penetrations in the Harweel area, encouraged continued exploration of the A2C Stringer. The urgency to pursue this stringer increased after the discouraging results of A3C exploratory appraisal efforts in the Sarmad field. By 2000, the strategy for stringer exploration in the SOSB became increasingly focused on unlocking the hydrocarbon potential of the A2C cycle. Zalzala-1 (2000) (Figure 17) was therefore drilled with the A2C as the primary objective. The well (spudded September 27, 2000) found the 4,931-m-deep objective stringer to consist mainly of a massive porous dolomite reservoir. More importantly, the hydrostatically pressured stringer (11.0 kPa/m) was oil-bearing. A total of 55 m of net pay with an average porosity of 10% was evaluated. Upon testing, the A2C stringer flowed over 3,000 bbls/d of 42^o API oil. Success in Sakhyia-1 and Zalzala-1 sparked interest in other A2C prospects, and necessitated the quick delineation of this stringer’s fairway. Between 2001 and 2002, three more A2C discoveries were made. These were Rabab-1 (2001), Fayrouz (2002) and Dafaq (2002) (Figure 17). This string of commercial success was only interrupted by Shujirat-1 (2002), which found the A2C cycle water-bearing.

The search for other play fairways started as early as 1999 (Figure 19). The first outstep well drilled outside of the Harweel Cluster was Ajeeb-1. Located southwest of the Ghafeer-Sarmad-Harweel discoveries, the well’s primary objective was the basal Ara stringer, which had proven to be a viable reservoir in the Dhahaban South area. The objective stringer showed promising reservoir properties, but lacked commercial hydrocarbons due to the absence of a base seal. Attempts to unlock the hydrocarbon potential of the basal Ara stringer continued in 2000 with the drilling of Asala-1. Unfortunately, in both holes drilled in this well, the objective stringer was absent.

Naqawah-1 (2000), located 17 km northeast of Harweel Deep-1, was drilled to test a stringer slab that was interpreted as a reefal build-up based on seismic character. The interpretation was influenced by a 6 sq km outcrop analogue from the Nama Group in Namibia called the Driedoornvlagte bioherm, which consisted mainly of grainstone and thrombolite facies. Unfortunately, the 140-m-thick objective stringer in Naqawah-1 consisted mostly of non-reefal, tight lime-mudstone facies. In 2001, the search for another productive fairway shifted the evaluation efforts to the northern part of the SOSB. A review of the intrasalt carbonate stringer prospectivity in the Northern Carbonate Domain of the SOSB, carried out in 1999, resulted in the identification of 43 drillable prospects. The Tharwah prospect was selected as the first strategic test of the Ara play in this area because it was deemed to be the most likely test of maturity, charge and reservoir quality in this part of the basin. Tharwah-1 (spudded in 2001, Figure 19) found all objective stingers water-bearing with poor reservoir development. Consequently, the charge and reservoir risks for surrounding prospects were increased and the portfolio volumes of the area were negatively impacted.

The drive to expand the play fairway beyond Harweel intensified in late 2001. This change in strategy was influenced by two factors. The first was the fact that a significant portion of the stringer prospect portfolio resided in areas outside the Harweel fairway (Larroque et al., 2002). Secondly, the remaining potential in Harweel had been reduced by exploratory appraisal drilling. As a result, the 2002–2004 stringer exploration program was largely geared towards testing opportunities outside Harweel. While exploratory appraisal activities in the Harweel area continued, the activity level was lower. The first outstep well drilled as part of this expansion campaign was Lahan-1 (2002) in the Thumrait North area (Figure 20). This 30-km-outstep west of Harweel, was drilled to test a deep intrasalt carbonate stringer, prognosed to be equivalent to the A2C of the Harweel Area. With no economic hydrocarbons found in the Western Deformation Front, Lahan-1 represented the first test for the intrasalt carbonate play in the transition zone between the Western Deformation Front and the SOSB. The well penetrated an unexpected stratigraphy represented by overthrusted Abu Mahara diamictites above a gas-bearing Ara carbonate platform. Further testing is planned to establish the commerciality of this hydrocarbon accumulation.

Minassa-1 was the second outstep well drilled in 2002. Located 10 km to the southeast of the Harweel area, the well represented the first dedicated test of the reservoir potential of the A1C carbonate stringer since the revival of the stringer play in 1997. Favorable primary reservoir facies were encountered in the objective stringer, but detailed core analysis revealed the A1C to be extensively plugged with salt and bitumen. The reservoir zone was perforated twice, but only traces of oil were recovered.

In 2003, three additional outstep wells were drilled. The first was Minha-1, which attempted to extend the A3C fairway west of the Greater Birba Area. In addition, the well also intended to test the extent of the A2C fairway, which had so far been proven to work only in the Harweel area. Both objective stringers were evaluated as hydrocarbon-bearing, but did not flow on a production test. The well was therefore abandoned. Ghaniya-1 (2003) was another well drilled to extend the A2C reservoir fairway, but in this case to the northeast of Harweel. The well established the presence of the A2C stringer, but with poor reservoir quality. To test reservoir development of the same cycle to the southwest of the Harweel cluster, Qashoob-1 was drilled the same year. This well, which represented the second well in that area following the disappointing results of Ajeeb-1, encountered hydrocarbons in the A2C, the commerciality of which remains to be proven. The last outstep well to be drilled in this campaign was Dhahaban East-1 (2004). The well was drilled to test the reservoir development of the A1C cycle in a 320 sq km structure. The objective reservoir, which was found to be tight, consisted mainly of peritidal carbonates interlayered with anhydrite.

The first reserves addition from the intrasalt stringers resulted from the first exploration phase in the Birba and Dhahaban areas. Approximately 274 million barrels of oil-in-place were discovered during the period from 1976 to 1986. Most of these volumes were contributed by Birba’s A4C Stringer (Figure 21). Additional volumes were contributed by A3C from the Durra and Kaukab discoveries.

A smaller contribution was added from the A5C Stringer with discovery of oil in the Omraan structure. The short-lived stringer exploration phase from 1988 to 1990 did not add any reserves. The second wave of reserves additions started with the third stringer exploration phase which began in 1997. Over 1.6 billion barrels of oil-in-place were discovered during the period from 1997 to 2002 (Figure 21). Initial volumes were provided by A3C discoveries, such as Harweel Deep, Ghafeer, Sarmad, and Sakhiya. Subsequent reserves additions were contributed by A2C discoveries from fields such as Zalzala, Dafaq, Fayrouz and Rabab.

Production from the Ara stringers started in the mid-1980s, several years after the first discovery well, and was initially from the Birba field. In 1985, Kuakab field went online to become the second producing stringer field through the Birba facilities. Faced with production decline, the Birba field was put on a gas-flooding system in the early 1990s for pressure maintenance. This led to an improvement in the production performance (Figure 22). Limited reserves in the Greater Birba area, however, curtailed further development of other discoveries. The second phase of stringer-field development involved the discoveries made in the Harweel area. Efforts to develop the reserves there did not start until 2001. The remoteness of the Harweel fields from existing infrastructure required the discovery of sufficient volumes to justify their development. The discovery of Harweel Deep, Sarmad, and Ghafeer provided the required reserves to fast-track the development of oil from these fields.

The field development plan for the Harweel Cluster stipulated that the optimal development of these carbonate stringer reservoirs would initially be through depletion and subsequently through miscible gas injection and flooding. The initial development phase involved the Sakhiya A2C, Zalzala A2C, Dafaq A2C, and Ghafeer A3C reservoirs. First oil was produced from the Harweel Cluster with the opening up of the well Zalzala-2 in March 2004 (Figure 22). As intended, this development stage delivered 11,000 bbls/d from these fields by the end of 2004. This stage also intended to prove-up the technical viability and economic robustness of full-field development through miscible gas flooding. A successful early development phase will be followed by full-field development through depletion of the remaining reservoirs. These will include: Ghafeer A2C and A3C, Sarmad A3C, Harweel Deep A3C, and Sakhyia A3C. In addition, a miscible gas-flooding pilot will be started in one reservoir. Success at this stage will be followed by gas injection implementation in suitable reservoirs in stepwise fashion. Based on miscible gas flooding, production from these reservoirs may yield a plateau production rate of 50,000 bbls/d or greater. These reservoirs are therefore positioned to significantly contribute to PDO’s oil production.

The 1997 successful revival of the play was the result of large investments made in seismic acquisition, processing, data collection, and integrated geological studies involving both inhouse staff and outside experts. The Ara intrasalt stringers, however, still remain a challenging play. The complexity of this system has clearly been highlighted during the drive to expand the play outside of Harweel. With a substantial part of the prospect portfolio of the play still untested and mostly residing outside of Harweel, a significant number of future wells will be drilled outside this main fairway. To maximize the future success rate, the increased play risks resulting from the last drilling campaign should be addressed. This will require significant improvement in seismic imaging, prediction of reservoir quality and occurrence, improving reservoir productivity, and further unravelling the hydrocarbon charge history.

Stringer exploration in the 1970s and to the late 1980s was entirely based on 2-D seismic data. After Harweel Deep-1, acquiring high-quality 3-D seismic became a prerequisite. The discovery of oil and subsequent exploration success in Harweel led to the acquisition of 5,758 sq km of eight new 3-D seismic surveys between 1997 and 2001 (Figure 23). These surveys were generally acquired with long-offset, high-fold, and deep recording depth. Significant improvement in the quality of the data was achieved by careful velocity picking and multiple removal (Al Lawatia et al., 2000). Since its first application in 1997, a total of 5,513 sq km of seismic data have been reprocessed with Pre-Stack Imaging (PSI) (Figure 23a). This technique is routinely used to unravel the internal connectivity, size and the number of stringer layers. Since 2000, reprocessing with Pre-Stack Depth Migration (PSDM) has been routinely applied to improve the imaging of the lateral extent of the stringers, their accurate position and internal faulting (Figure 24) (Al-Yarubi and Asmussen, 2004).

Existing 3-D surveys in South Oman have been merged (post-stack) into large mega-grids, covering several thousand square kilometers, to enable effective regional mapping (Figure 23). These large seismic grids have been instrumental in addressing key risk factors in reservoir development, charge, trap and seal integrity (Figures 23 and 25). Despite the existence of large areas of seismic data reprocessed with PSI and/or PSDM over the SOSB, proper imaging of some stringer cycles still remains a challenge. Multiples still complicate the proper imaging of these stringers. This issue was clearly demonstrated in some recently drilled production wells where the objective reservoir was found missing despite an apparent continuous reflector at the objective level.

Improvements can also be made in the area of seismic interpretation. Volume interpretation could provide better visualization of the external geometries of stringer bodies and their internal discontinuities can be highlighted as part of fast track interpretation of new data sets prior to detailed mapping (Engbers et al., 2004). Quantitative seismic interpretation and inversion techniques have not been rigorously applied, mainly due to the depth at which these stringers occur and the quality of the seismic data. Furthermore, the non-unique amplitude response and the occurrence of multiples preclude, at the moment, reliable inversion studies. Reshooting of seismic over some parts of the play fairway using improved acquisition parameters and advanced reprocessing techniques, could yield improvements in this area. By providing a better handle on reservoir rock distribution prior to drilling, these advanced seismic studies will allow for better positioning of future exploration wells.

Since the comprehensive work of B.W. Mattes and L. Gaarenstroom in 1984, significant advances have been made in understanding of the stringer depositional systems. A diverse assemblage of facies has now been recognized to comprise the Ara carbonates cycles (Schröder, 2000; Schröder et al., 2000a, b; Grotzinger, 2000; Grotzinger and Amthor, 2002; Schröder et al., 2003; Schröder et al., 2003, 2004). Peritidal facies consist of fine dolostones with associated anhydrite nodules. Sedimentary features in this lithofacies association include reworked pisolites and tufted mats (Figures 26a and b). Shallow-platform facies of the Ara Group include ooid-intraclast-skeletal grainstones, coarsely-laminated stromatolites, and oncolite packstones (Figure 26c). Platform barrier and buildup facies include a variety of stromatolitic and thrombolitic lithologies (Figure 26d). Slope facies are organic-rich, rhythmically-laminated dolomite or lime mudstones with interspersed massive mudstone beds and common soft-sediment deformation structures (Figure 26e). Some of the carbonate platforms developed steeper slopes, often characterized by shelf- and slope-derived allodapic breccias. Basinal facies in all stringers are dominated by sapropelic, finely laminated dolomite mudstones (Figure 26f). Reservoir facies include dolomitized shallow-water thrombolites and grainstones as well as peritidal laminites (Figure 27). In addition, basinal sapropelic laminites form another reservoir facies whose performance deteriorates in proportion to the influx of turbiditic shelf-derived muds. In the basinal facies, commercially viable reservoir properties were created during early diagenesis of organic matter, which created abundant fenestrae.

Seismic ‘stringers’ are interpreted to have been deposited originally as large carbonate platforms that were subsequently deformed or completely fragmented due to later salt movement. These platforms formed during transgressive to highstand accommodation conditions, superimposed upon a progressive, long-term accommodation increase, which forced platforms within each cycle to occupy progressively less area (Amthor et al., 2005) (Figure 28). The absence of extensive Ara outcrops and the lack of seismic depositional geometries in most of the Ara sequences hampered attempts to reconstruct the depositional profiles of each of the various Ara cycles. The well-studied and time-equivalent outcrops of late Proterozoic to Early Cambrian Nama carbonates in Namibia are similar to the Ara stringers in tectonic setting, stratigraphic architecture and facies distribution (Adams et al., 2001, 2005; McCormick and Grotzinger, 2001; Amthor et al., 2002). An improved understanding of reservoir architecture and platform geometries was achieved by comparing the Namibian rocks to the Ara subsurface database. Ara platform geometries are, therefore, envisaged to have ranged from low-gradient ramps to rimmed shelves (Figure 29). Thus, there is no single stringer facies model; rather, each stringer contains favourable reservoir facies whose distribution depends on the history of platform development including eustatic, tectonic, and palaeoenvironmental influences.

Future commercial success depends strongly on understanding the facies model for each stringer, dolomitisation, and porosity occlusion by bitumen and/or halite plugging. Dolomitisation enhances both permeability and porosity of facies that have high initial porosity (Hollis et al., 2002). It is also limited to one phase of early recrystallization (Schröder et al., 1998; Schröder, 2000), and does not help to transform initially non-reservoir facies (e.g. mudstones) to reservoir-quality pore systems. On the other hand limestones, even if present in facies known to have high initial porosities, will characteristically have dramatically lowered porosities and permeabilities due to the effects of aggrading neomorphic recrystallization.

Reservoir quality is also influenced by the degree of halite and bitumen plugging, which can be very detrimental to porosity preservation. The Minassa-1 production test has clearly demonstrated the devastating effect of having bitumen and halite in the pore spaces. Despite favourable primary reservoir facies that were evaluated as hydrocarbon-bearing, Minassa-1 failed to produce any hydrocarbons upon testing. Extensive bitumen and halite plugging of the pores in this well have drastically reduced the effective porosity and permeability of the A1C reservoir (Al-Abry et al., 2004). Although many stringer wells in the SOSB were known to contain bitumen and halite at various concentrations, Minassa-1’s production test was the first documented case where flow was impeded as a result of this type of plugging. At this point in the history of the play, halite and bitumen plugging represents one of the greatest unknown risks for both exploration and development. Pore networks that are well-preserved in dolomitized facies with high initial and secondary porosities (e.g. thrombolites) can still be completely occluded as a result of later migration of precipitating high-salinity brines through open pore systems. This plugging appears to both predate and postdate hydrocarbon migration and is currently only poorly understood. With more than one generation of solid bitumen documented, the origin of this substance is also poorly understood. Deciphering its origin and constraing its aerial distribution will require a thorough understanding of the thermal evolution of the SOSB, particularly during Ara times.

Another area that has not been fully unravelled is the hydrocarbon charge history of the stringers. Based on source rock analysis and charge modelling, Frewin et al. (2000) concluded that the majority of intrasalt reservoirs penetrated in the SOSB must have been self-charged (Figure 30a). This assumption had been the accepted charge model since the first stringer well was drilled in 1977. Recent geochemical work on the stringers, however, has concluded that the oils within the carbonate stringers show a range of geochemical characteristics consistent with an origin from either intrasalt or presalt source rocks. Candidate source rocks include organic-rich shales interbedded in the Ara salt, such as the ones found within the A3 section of Harweel Deep-1 (TOC 6%). High TOC values of 5% have also been measured from several organic-rich horizons in the presalt Nafun Group (Masirah Bay, Shuram and Buah formations). Within the carbonate stringers so far, however, only marginal source rocks have been documented with TOC values of 0.4%. The most prolific source rocks in the Ara Group are those of the Athel trough, which have recorded TOC values that range from 1–10% (Nederlof et al., 1997; Terken et al., 2001; Kowalewski et al., 2002), although the possibility of stringers such as those in the Harweel Cluster having been attached to the Athel shales and silicilytes appears remote.

Recent advances in biomarker interpretations have shown an unequivocal link between the laminite kerogens and stringer oils for the first time, meaning that the stringers represent, at least in part, a self-charged system. However, understanding the extent and distribution of presalt charge contribution is the topic of current work. A presalt charge component is clearly apparent in the gases associated with the carbonate stringer oils. This conclusion is based on the occurrence of higher concentration of isotopically heavy methane in the older gas-bearing Ara cycles. The reduction in concentration, or the complete absence of this type of methane in the younger cycles, indicates input from the underlying presalt stratigraphy (Paul Taylor, oral communication, 2004). An external or mixed charge is therefore possible for the lower and stratigrapically older Ara cycles, particularly those situated along presalt structural highs (Figure 30b).

The future of source rock prediction depends very much on the ability of new studies to distinguish between various types of microbially-produced organic matter. Precambrian, microbially-dominated ecosystems were inhabited by a diverse array of micro-organisms, including those occupying pelagic and benthic niches (Summons and Walter, 1990). In addition, the benthic micro-organisms were strongly dependent on water depth, light availability and redox state. Finally, it has now been established that stringers span the Precambrian-Cambrian Boundary, a time marked by extinction and subsequent radiation of early metazoans (Knoll and Caroll, 1999; Amthor et al., 2003). Ongoing studies will exploit the occurrence of anomalous enrichment (or depletion) of geochemical signals that resulted from perturbation of the Huqf petroleum system due to global tectonic, palaeooceanographic and biological evolutionary changes at the Precambrian-Cambrian Boundary. In this manner, it may be possible to delineate specific source rocks through understanding their palaeoecology using predictive sedimentologic models and state-of-the-art biomarker geochemistry.

Over the past 27 years, the Ara intrasalt stringer play has undergone three exploration phases. In the first two, the play was unable to deliver substantial reserves to justify continued exploration. In the final phase, on the other hand, the play benefited from the availability of a large data sets of 3-D seismic over extensive areas of the SOSB. The discovery of commercial oil in Harweel maintained stringer exploration activities, which has since been sustained by further success in finding more reserves. The Ara stringers have steadily become the main contributor of the bulk of exploration’s annual reserves targets. This intense evaluation effort has also resulted in a substantial growth of PDO’s play prospect portfolio. The demand to meet reserve targets necessitated the search outside of Harweel where sizable opportunities still existed. These attempts, however, have had limited success, raising serious doubts as to the play’s future sustainability.

Despite being scrutinised for such a long period, the stringer play still poses great challenges because of its complexity. Success outside of Harweel will require significant advances in a number of areas. Seismic imaging is one of those areas where advances in quantitative interpretation and inversion studies may possibly allow for the better positioning of future exploration wells. Predicting reservoir rock distribution outside the Harweel area is another challenge. Existing reservoir models are based on data acquired from wells drilled in Harweel and therefore are limited in their predictive capabilities. Furthermore, recent well results have demonstrated that commercial success is not only limited to the presence of favourable facies, but also the occurrence of reservoir. Diagenetic processes, particularly halite and bitumen plugging, have proven to be effective inhibitors to attaining commercial flow from established reservoir facies. Studies that will shed light on understanding the causes and the distribution of halite and bitumen plugging will undoubtly influence future exploration strategy. Efforts should concurrently be invested in trying to access locked-up oil-in-place in these reservoirs with the utilization of innovative drilling and production technologies. The stringer play may benefit in this area from the experience gained in the Athel campaign.

The stringer play in the SOSB is clearly entering a new exploration phase. Learnings from this phase will influence the play evolution not only in the SOSB, but also in the Al Ghabah and Fahud Salt Basins where the Ara Group is a potential exploration target. If history is any guide, the Ara carbonate stringers will always remain part of exploration’s future activity plan.

The Ministry of Oil and Gas and the Exploration Management of Petroleum Development Oman L.L.C are thanked for their permission to publish this paper. Many individuals have been involved with stringers over the past 27 years. The first comprehensive work on the sedimentology, stratigraphy and hydrocarbon potential of the Ara was provided by B.W. Mattes and L. Gaarenstroom in an internal report published in 1985. T.A.L Teyssen’s internal work in 1990 was valuable in refining the Ara stratigraphy in the SOSB. The following individuals are also acknowledged for their contribution to our current understanding of the carbonate stringer play: Joachim Reinhardt, Bruce Levell, Joachim Amthor, John Grotzinger, Jean-Michel Larroque, Mark Newall, Gilles de Broucker, Folco Hoogendijk, Ruwina Al-Riyami, Jack Woodward, Muatasam Al-Raisi, Radha Al-Lawatia, Mia van Steenwinkel, Mohamed El-Tonbary, Rashid Al-Hashimi, Sultan Al-Harthy, Khairan Al-Mauly, Fahar Al-Rabeei, Robert Gardham, Joao Rodrigues, Nadia Al-Abry, Paul Taylor and Saada Al-Rawahi. The Athel part of this paper has benefited from the work of the following individuals: Tom Faulkner, Joachim Amthor, Karl Ramseyer, Jan Hartsink, Folco Hoogendijk, Stuart Lake, Marcus Antonini, and Recep Kazdal. PDO, Shell and other geoscientists who have been involved with Ara over the years, but unintentionally were left out in this acknowledgment, are equally thanked. Anwar Al-Balushi and Willie Quizon are thanked for redrafting some of the old figures used in this paper. This manuscript has benefited greatly from reviews by Mark W. Shuster, Jan Schreurs, Alan Heward, Andrea Cozzi, Shane Pelechaty, Paul Nicholson and two anonymous reviewers. The final design and drafting of graphics by Gulf PetroLink is appreciated.

Hisham A. Al-Siyabi holds a BSc in Geology from the University of South Carolina (1992), and an MSc (1994) and PhD (1998) from The Colorado School of Mines. Hisham joined PDO in February 1999, and since 2001 has worked as a Team Geologist/Seismic Interpreter with the South Oman Frontier Exploration Team working exclusively on the Precambrian intrasalt Ara stringers. Since 2005, Hisham was cross posted as an exploration geologist to Shell Exploration and production company in New Orleans, Louisianan (USA). Hisham was President of the Geological Society of Oman from 2001 to 2004.