Mamdouh Nagati
International Petroleum Corp.
Dubai
For several decades oil companies have failed to mimic the traditional play concept of the Gulf of Suez by targeting potential oil reservoirs below the Upper/Middle Miocene salt in the Red Sea.
The absence of a Pre-Miocene sequence in the majority of outcrops on both sides of the rift and its assumed absence in the subsurface, together with the perception of the Red Sea being geothermally hot and only gas-prone, have led to an exploration lull in this 280,000 sq mile intracratonic rift basin.
The depositional or erosional edge of the marine Eocene to Upper Cretaceous beds, which sourced the majority of the oil in the Gulf of Suez, does not extend southward beyond 26 N. Lat. and is limited to a small outcrop in Quseir on the Egyptian side of the Red Sea hills.
Similarly, at the southern end of the rift, the Upper Jurassic carbonates which sourced the majority of the oil in Ma'arib Al Jawf-Shabwa basin in Yemen are not evident northward beyond 15 N. Lat. In the subsurface, the absence of the Pre-Miocene source beds was further supported by nearly 50 deep wells which bottomed in basement.
The complete absence of Pre-Miocene in the subsurface is still debatable as the early subsidence of the basin floor might have resulted in preservation of some Pre-Miocene blocks in areas not yet tested by drilling, while the continued isostatic uplift has led to complete removal of the prerift sedimentary cover on the basin shoulders. This possibility, however, is now becoming increasingly remote and may be taken into account only as a secondary, deeper target in future drilling, particularly with the proven high heat flow in the pre-salt.
The only exception to this regional observation is a thin, possibly Upper Cretaceous, marine section in the Maghersum-1 well in central offshore Sudan, which included shales with total organic carbon (TOC) values as high as 10%.
In the Gulf of Suez, the Lower Miocene shales and marls have proved to be of marginal importance in the process of hydrocarbon generation. This is mainly due to the insufficient maturity and relatively low organic content.
While the maturation levels are considerably higher in the Red Sea, samples obtained from 44 wells which have penetrated through the Miocene salt have failed to prove significantly rich oil-prone source beds.
However, oil seeps and liquid hydrocarbons recovered during testing or identified in drill cuttings in a number of wells spread across the length of the Red Sea are puzzling geologists who are still seeking a breakthrough to reveal their origin.
These liquid hydrocarbons include 1 bbl of 43 gravity oil from the Abbas-1 well in Yemen, 10 bbl of 36 gravity oil from the Adal-2 well; unknown amounts of condensate associated with 5-10 MMcfd of gas from the C-1 well blowout in Eritrea; 1,158 b/d of 52 gravity condensate from the Suakin-1 well in Sudan; 34 gravity oil samples from the Mansiyah-1 well; oil seeps on Farasan Island in Saudi Arabia; and oil shows in the Quseir A-1 and B-1 wells in Egypt (Fig. 1).
If the pre-salt source beds are either missing or organically lean, or too hot to generate liquid hydrocarbons, where then do these oil shows come from?
Although the quantities of the recovered liquid hydrocarbons are small, they still indicate that somewhere within the section there are source beds capable of generating oil and wet gas. Could the salt and postsalt sediments provide satisfactory answers?
BEST LIQUID RECOVERY
In fact, out of the 70 wells drilled to date in the Red Sea, fewer than a dozen of them targeted post-salt structures. By far the best recovery of liquid hydrocarbons in the Red Sea region was achieved in the Suakin-1 well southeast of Port Sudan.
Suakin-1, which was drilled by Chevron in 1976, achieved a stabilized flow of 6.9 MMcfd of gas and 1, 158 b/d of condensate on 48/64 in. choke from a sandstone reservoir within the postsalt Upper Miocene Zeit formation.
The 28 ft net pay, which was cored and confirmed a porosity of 21% and a permeability of 147 md, had an open flow potential of 17.4 MMcfd of gas and 2,925 b/d of condensate. This zone was the deepest reservoir tested in the well as mechanical problems while drilling led to the loss of the bottom 1,353 ft when the drill pipe became stuck.
To allow for testing, the pipe was backed off at the free point, and the fish was milled down to 7,700 ft, immediately below the tested zone.
Samples and chromatography records indicated that the unlogged section between 7,988 ft and the TD at 9,003 ft contained 300-400 ft of net sandstone reservoir with similar wet gas shows.
In addition to this potential reservoir, at least 500 ft of undrilled possible Zeit formation is estimated to exist within closure. Similarly, there could be more sandstone reservoirs faulted out in the well location by a major east-west listric fault above the tested zone in the southern half of the huge Suakin structure.
A modern 2D seismic survey consisting of 1,050 km shot over the Suakin area in May 1992 indicates a complex structural and stratigraphic setting. Fortunately, the stratigraphic package which contains the proven reservoir is a simple turtle back rollover cored at depth with a thick salt pillow intercalated with several clastic beds (Fig. 2).
Delta lobes which are evident on the flanks of the structure rest on a faulted and evacuated salt substratum where the major listric fault soles out near the base of the massive Middle Miocene salt (Fig. 3).
Shallower in the section, the Upper Zeit formation and younger sequences are broken by several growth faults terminating on a thin salt decollement surface (Fig. 4).
The condensate recovered on test was somewhat waxy and paraffinic, indicating a mixture of terrestrial and aquatic organic source material typical of a prograding deltaic environment. By analogy with the distribution of hydrocarbons in well known deltaic sequences elsewhere, the dry gas discovery in Bashayer-1 and gas/condensate discovery in Suakin-1 point to the high probability of discovering oil or at least wetter gas in post-salt structures more distant from the paleo shoreline in the Tokar Delta (Fig. 5).
One of the analogs to the Tokar and Halaib Deltas is the Middle Miocene Cruse formation offshore Trinidad.
In this proto-Orinoco Delta, all the gas fields are nearer to the shoreline, while the oil fields of Galeota, Samaan, and Teak are farther away from the deltaic sediment input. The same situation is observed in the Eocene deltaic sediments of the Latrobe formation in the Gippsland basin between Australia and Tasmania, where the delta prograded southward and the most nearshore (northerly) fields produce gas, while a series of oil and gas fields (e.g., Marlin and Barracouta) exists southward in deeper water.
ZEIT RESERVOIRS
The Zeit reservoirs anywhere in the Red Sea are mainly texturally and mineralogically immature sands and sandstones sourced from the adjacent granitic basement outcrops and deposited in a fluvial to shallow marine environment. The reservoirs frequently have good porosities and fair to good permeabilities.
Sealing is generally poor nearshore as coarse clastics are predominant, but to seaward, sealing shales become more and more evident until seal lithologies exit to a fair degree further offshore. The halite and anhydrite beds of the Upper Miocene Zeit formation and the upper salt (of the South Gharib equivalent) have regional extent as proved in the Gulf of Suez. They form an excellent widespread, mappable, and predictable seal everywhere in the Red Sea, below which significant oil and gas shows have frequently been detected.
The high temperature gradient, in the author's opinion, was mistakenly interpreted as writing off the potential of the post-salt sedimentary section, and large scale geothermal gradient maps for the whole Red Sea are a pessimistic simplification. There is no doubt that the Red Sea, being a thermally active rift basin, is now generating heat flow significantly higher than average.
Nevertheless, it seems that the different thermal properties of the rocks and the associated movement of pore fluids have not been taken into account in the maturation assessment. In Suakin-1, vitrinite reflectance and spore coloration measurements indicate considerably lower maturity values when compared with those derived from the recorded bottom hole temperatures, indicating hot fluid movements from deeper horizons.
In tectonically quiet basins like the Arabian Gulf and in other subdued major relief basins with uniform or flat layered substratum, the isothermal surface will consist of horizontal planes even if there are contrasts in the thermal conductivity between the various layers. However, in the presence of lateral conductivity contrasts, the heat flow will be focused by bodies of high conductivity and deflected by bodies of low conductivity.
In the Red Sea, the particular bodies which produce temperature anomalies are the salt diapirs, between which the mainly shaly section of the Zeit formation exhibits much lower gradients.
Salt and anhydrite are extremely conductive to the heat flow (14 and 12 mcal/cm sec C., respectively), while the clay and shales of the Zeit formation are, in contrast, the least conductive (2 and 6 mcal/cm sec C.).
Salt domes will act as chimneys and conduct positive temperature anomalies to their roofs. Therefore, wells drilled on high salt structures could easily show 2-3 times the regional average temperature gradient.
A quick glance at seismic profiles anywhere in the Red Sea clearly indicates that the isothermal map of the Red Sea must be a fairly complex one. In areas of excessive post-salt sedimentation, down to the basin listric faults will accommodate the clastic loading and will produce salt withdrawals at the basin margins and a series of salt diapirs.
In the area between the listric faults and the salt diapirs, the Zeit and post-Zeit formations will be situated in an ideal play fairway suitable for hydrocarbon generation and entrapment (Fig. 6). The high heat flow emitted by salt diapirs will enhance the thermal maturity of the adjacent undrilled pro-delta clay zone, enabling liquid hydrocarbons to migrate westward and eastward, towards the African and Arabian coasts, and fill rollover structures before excess hydrocarbons emerge as surface seeps on coastal plains or islands.
Given the relatively young age of source and reservoir rocks, the enhancement of preservation of liquid hydrocarbons will place the oil floor deeper.
Since we are targeting rocks younger than 10 million years, oil could still be preserved as deep as 12,000 ft, given the present day temperature gradient in the Suakin area.
Moreover, high reservoir pressures tend to increase the preservation of liquid hydrocarbons, while the paraffinic oils from lagoonal and mixed terrestrial/marine source rocks have a higher thermal stability compared with the purely aromatic marine oils.
OLDER DELTAS
The two deltas of Tokar and Halaib are easily identifiable on the western coast of the Red Sea. Nevertheless, other older deltaic facies should have also existed across the length of the 2,500 mile long Red Sea coastlines, particularly in Eritrea and Yemen.
In the majority of the basin, the environment has become more and in the Pleistocene-Recent and the influx of sand and shale has almost ceased, giving rise to clear water and carbonate buildups which could mask older deltas.
In areas of nondeltaic facies, the possibility of marine oil generation is even greater, although possibly in lesser quantities than the gas and condensate.
The multiple stacked layers of algal mats in the upper salt/Lower Zeit beds, in particular, act as a potential source and are probably optimally mature for oil generation.
Present day models from the Abu Dhabi Sabkha demonstrate the richness of this algal source where TOC values average 5.75 wt % and S2 values are 10.7 kg/ton.
These algae, growing in hypersaline environments where the bacterial degradation is least effective and where anoxic conditions prevail, are capable of producing as much as 3.66 kg oil/ton of rock.
Additionally, there is seismic evidence for structural lows at top salt level near the axial zone of the Red Sea. These lows are probably a direct result of salt withdrawal either towards diapirs or into the axial trough. The halokinetic lows which were distant from the source of clastic input in the Plio-Pleistocene have high potential for accumulation of source sediments.
Under the high heat flow at the axial trough these young sediments could easily reach peak generation levels and produce hydrocarbons at relatively shallow depths of burial.
Obviously, the post-salt section in the Red Sea does not lack the reservoirs, seals and four way dip closure components (Fig. 7). Apart from the triangular shapes of the Tokar and Halaib Deltas as evident from surface and isobathymetry maps, there is little known about the net sand distribution patterns in the subsurface.
The environmental setting conducive to the formation of deltas in a low energy, narrow, restricted basin similar to a lake type, suggest fingerlike protrusions of channel sands. The sand fingers represent sand-filled channels and linear sand bodies deposited by tidal action.
The abundance of sand in the two Upper Miocene known deltas, as demonstrated by Halaib-1, Bashayer-1 and 2, Suakin-1, Digna-1, Marafit-1, and Durwara-1 and 2, is not in doubt. In fact, the seal rather than reservoir might be the main risk in structures adjacent to the paleo alluvial valley and distributary channels.
Among the six structures tested, Suakin and Bashayer were the only sealed structures. Existing seismic data on both continental shelves of the Red Sea demonstrate many high relief structures either cored by salt or governed by listric growth faults.
Under this complex structural regime, high pressures induced by salt flowage and piercement have allowed the generated hydrocarbons to migrate out of the aquatic algal or pro-delta source beds through the open listric faults.
In structures like Suakin, where hydrocarbons and water bearing sands coexist within a short vertical distance, certain reservoir beds were juxtaposed against the source rocks at the time of hydrocarbon expulsion and were charged with wet gas. When mobile salt layers juxtapose each other across fault planes, hydrocarbon migration across or along the fault planes was prohibited.
Dry hole assessments show that whenever post-salt structures were tested but found to be dry, there was no adjacent kitchen area of pro-delta clays or a salt wall present to enhance the maturity of the stacked algal source layers. The combination of these four classic factors remains the key to further success.
MORE DRILLING PLANNED
When gas and condensate were discovered in Suakin-1 in 1976, there was no incentive to delineate the field and drill an appraisal well since there was no economic outlet for the associated gas.
Under different contractual arrangements a second well will be drilled 200 ft updip, approximately 6 miles to the east of Suakin-1, to test the 77 sq mile (50,000 acre) closure all the way down to the last closing contour, penetrating around 1,700 ft of gross vertical relief (Fig. 2). The well will also test the updip hydrocarbon potential of the 30 ft zone which flowed water from a section immediately above the gas/condensate pay zone in Suakin-1 in addition to a gross 700 ft of water wet, highly porous sands below 5,500 ft.
Assuming the 28 ft net pay extends over the whole structure, proven recoverable reserves were estimated at 831 bcf of gas and 79 million bbl of condensate. The new near Top Suakin sand map indicates that Suakin-1 was, in fact, drilled on the flank of the structure, and that the majority of the structure remains untested.
If the successful appraisal well proves additional deeper reservoirs as evident from the gas log, the upside potential could easily amount to 15 tcf of gas and 1.5 billion bbl of condensate.
Current plans are to commence production from two wells through an early production system (EPS) upon the completion of successful testing of Suakin-2 and a reentry of the Suakin-1, which was temporarily abandoned.
The obvious operational problems in the Red Sea are the depth of water and the overpressure. However, on both sides of the Red Sea there is at least 128,000 sq miles of prospective area shallower than 650 ft. In certain parts, including the Tokar and Halaib Deltas and in the majority of Eritrea and Yemen, water depth does not exceed 350 ft.
Careful planning, pressure prediction, and modem drilling technology can overcome the overpressure hurdle, while, on the other hand, the young unconsolidated sediments of the postsalt are easy to drill at low cost.
Further development and additional exploration wells in the Delta Tokar permit will enable explorationists to understand the complex relationships of source/reservoir in the post-salt sequence and may lead to a new exploration era in the Red Sea.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
