Morocco - Zag Basin and Tarfaya Basin

Zag Basin

Licence name Gross acres Net acres Gross km2 Net km2 SLE share
Zag 3,614,904 1,897,824 14,629 7,680 52.5%

1. Overview

On December 5th 2006 San Leon Energy signed an exclusive one year Reconnaissance Licence with ONHYM to conduct hydrocarbon exploration studies in the relatively unexplored and highly prospective onshore Zag Basin Licence in Morocco (Figure 1). In January 2008, the licence was converted into an eight year Exploration Licence. The licence area covers approximately 14,629 km2 or 3.62 million acres post-relinquishment, a vast area that includes the southern half of the Moroccan portion of the Zag (known as Tindouf in Algeria) Basin.

Figure 1

 Figure 1. San Leon Zag Licence location and key facts

The Zag Basin (known as the Tindouf Basin in Algeria) is the western most of the hydrocarbon prolific North African Paleozoic basins. Located on the western edge of the Sahara Desert, the Zag Basin is virtually unexplored. Yet a gas discovery and strong oil shows on the Moroccan side, gas discoveries adjacent to our licence on the Algerian side and in the southeastern extension of the basin (Reggane Basin) in Algeria, reports of gas seeps from San Leon’s Field Study, and the widespread presence of the famous Silurian oil and gas generating shale, indicate that this basin is no different than the world class Paleozoic petroleum province that extends across North Africa. EIA expect 75 TCF of gas and 5 billion BO to reside within the Moroccan Zag Basin. Sonatrach/EIA expect 135 TCF of gas and 2.37 billion BO to be found on the Algerian side of the Zag–Reggane Basins. San Leon estimates that within the Zag permits there is the potential for several TCF of gas with associated oil and condensate, based on the EIA World Shale Gas Report 2013, and Sonatrach’s Algerian projections; although there is a degree of uncertainty to the Western extent of the Silurian “hot shale” due to a lack of modern data, which would be challenging to acquire given the remote location of Zag Basin. San Leon has about half of the Moroccan portion of the Zag Basin. Exploration began in this final Saharan Palaeozoic basin with Anadarko, having completed (Summer, 2007) an AeroMag survey on the combined licences that comprise the Moroccan Zag Basin, and Sonatrach conducting technical work on the Algerian side.

2. Geology and Geophysics

A number of Paleozoic basins in North Africa, particularly those in Libya, Tunisia, and Algeria, carry notable hydrocarbon reserves. Extensive sedimentation of organic carbon rich shale during the Silurian and subsequent deposition of Early Devonian sandstones has established two of the key ingredients, reservoir and source, for the development of an excellent hydrocarbon system in the North Africa region. It therefore stands to reason that the Zag Basin, one of the major under explored basins in North Africa, with a Paleozoic sediment column in excess of 6 km in thickness including up to a kilometer of potential Silurian source rock, represents an excellent opportunity for both conventional and unconventional exploration. An assessment by OXY in 1989, PetroCanada in 2006, and San Leon in 2007 has confirmed the presence of Silurian hot shale, Ordovician, Early Devonian, Carboniferous sandstones and carbonates in the basin. The stratigraphic sequence of the Zag Basin is then very similar to that observed in the famous petroleum rich Paleozoic basins in Algeria and Libya.

Figure 2

 Figure 2. San Leon Zag Licence highlighting leads and prospects identified on 2D seismic

The Zag basin is recognized as a hydrocarbon province for gas in the central part, condensate in the south central, and oil in the southern part of the basin. Basin maturity analysis of the Silurian source rock shows that it is within the gas, condensate and oil windows over the San Leon Zag permits, while it may be over mature over much of Anadarko’s licence to the north. Long distance oil and gas migration would then be necessary to charge traps on the northern flank. Lower and Upper Devonian shales may provide additional sourcing potential within the basin.

San Leon has identified four main play types present within the Zag licence:

  1. Lower Devonian Emsian Sandstones: Analogous to “rich sandstones” observed in Tindouf and Reggane Basins of Algeria.
  2. Lower to Middle Devonian carbonates (patch reefs and platform carbonates): Sourced by Silurian Hot Shales or Lower Devonian shales (fault controlled, ramp style or patchy).
  3. Structural, multi-horizon traps: Fault-related and sourced by Silurian Hot Shales, Upper Devonian Shales.
  4. Unconventional shale gas reservoir: Most likely Silurian and Devonian age due to most favourable depths. 

EIA (2013) study estimates 75 TCF Silurian shale gas in-place, within the Moroccan Zag Basin.
A large number of leads and prospects have been identified on the 2D seismic data-set (see Figure 2). San Leon has identified a Lower-Middle Devonian-aged amplitude-anomaly Sidi Rgibi prospect that has been mapped over several seismic lines with an area of over 550 km2 (Figure 3), displays a high-impedance event and is fault-controlled. San Leon believes the prospect correlates with Middle Devonian platform carbonates and patch reefs, which can be observed outcropping near the town of Es Smara, to the south of the Zag licence.
Additional conventional prospectivity within the licence can be observed in structural multi-horizon traps associated with the Hercynian orogenic events that led to the formation of the Anti-Atlas Mountains. Structural leads are observed across the seismic data-set and in some locations exhibit over 2,000 m of structural closure between the Middle Devonian and Ordovician.

 Figure 3

 Figure 3. San Leon Seismic Basin-Dip Line ZA07 highlighting the Devonian Sidi Rgibi prospect (yellow), and structural fault-controlled closures 

San Leon estimates that present-day maturity of Lower Silurian shale is within the gas to condensate window within the Zag licence. In addition to several hundred meters of Silurian source rock, is the Tannezuft “Hot Shale”, a regional North-African world-class source rock with greater than 10 % TOC. Data analysis suggests that within parts of the Zag licence, the Tannezuft “Hot Shale” is up to 20 meters thick, within the gas maturity window, providing additional unconventional upside within the Zag licence.

Exploration history

Phillips Petroleum, AGIP (ENI), ARCO (now part of Exxon-Mobil), PanAmerican (Amoco and now BP), Gulf and Tidewater (now Chevron), and EMINENSA (a Spanish company) drilled forty wells in Morocco, Algeria, and the former Spanish Sahara in the late 1950’s and early 1960’s. Twenty of those wells, including shallow "core" wells, were drilled in what is now the Group’s Zag Basin Licence. No wells were drilled on the basis of seismic data and therefore drilling locations were selected from surface expressions. Seismic data acquired by Sonatrach on the Algerian side indicate that the subsurface is different structurally from the surface and therefore seismic data is necessary for identifying drillable prospects. No wells have been drilled since the 1960’s and after Spain released the Territory in the early 70’s. According to ONHYM, no seismic data has ever been acquired in the Moroccan part of the Basin, prior to the acquisition of 1,695km of 2D seismic by San Leon's seismic company NovaSeis in 2011.

Hydrocarbon shows and discoveries

Results of the Zag basin wells indicate a shallow gas discovery in the southern rim of the basin at the Morcba-1 well, two discoveries immediately east of the licence on the Algerian side and 9 oil and gas shows. Also, Repsol has made several discoveries in the southeastern extension of the basin, including one that could be between 700 BCF and 1 TCF. Sonatrach estimated that 3.2 TCF of gas had been discovered prior to Repsol’s finds (see Introduction for more details on the Reggane Basin). The Oum Doul-1 well, has an apparent oil seep that has been investigated by ONHYM and PetroCanada (now Anadarko)and in January, 2007 by San Leon.

The Morcba-1 well, drilled on the shallow southern flank in 1965 by Eminensa, a Spanish company, discovered gas from Devonian sandstones. It was reported from eye witnesses that the well flared for several days. Another well on the southern flank, the 18-D well, recovered gas following tests in the Middle and Early Devonian sections. A gas show was reported in well 12-1, in the central part of the Zag Basin Licence, while air drilling the Silurian section. Other oil and gas shows have been made on the Algerian side but those results will not be made available by Sonatrach.

On the northern flank of the basin the Oum Doul-1 well tested a small amount of dry gas from Carboniferous sandstones. The San Leon field geologists acquired fluid samples that appeared to have traces of oil at the Oum Doul well. PetroCanada conducted the same exercise in 2006 on the Oum Doul well and confirmed the oil seep on the basis of their geochemical analysis in their presentation at the May, 2007 Marrakech Conference. Oum Doul-1 was drilled on a surface anticline in 1959 by AGIP (ENI) to a total depth of 4,275m or 14,026’ in the Devonian. The AZ-1 well, drilled on the northern flank, tested gas. Again, long distance migration might be required to charge the traps on the northern part of the basin, where Anadarko's permits reside.

According to ONHYM’s geologists a water well, known for its oily sheen, resides in the northern part of San Leon’s Licence. Another report from the field trip stated that a gas seep, discovered by nomads and actually used for cooking, exists in the central part of the licence.

3. Initial period key work obligations and progress

Work program commitments & completed work:

  • Merge the Zag Basin (San Leon) Aeromag data with the Bas Draa (Petrocanada Anadarko) data;
  • Acquisition, processing and interpretation of 500 km of 2D seismic;
  • Cross Section of the regional structure;
  • Basin modelling;
  • Source rock evaluation;
  • Petro-physical study of existing well data in the area
  • Fieldwork. The field program in the Zag Basin began on 10 January, 2007 in Es Smara, located on the eastern edge of the Zag Basin Licence. Geological sampling and field work was conducted on the south and north sides of the western Zag Basin and ended in Agadir on 20 January. 21 reservoir, 12 shale, and 2 fluid samples, from the Oum Doul well, were collected. A regional field program took place in June 2013, which incorporated the investigation of Ordovician-aged Hercynican-related structures near the village of Icht, Silurian and Ordovician source rock field studies, and observations of Middle Devonian reefal assemblages near Es Smara.
  • Geochemical Study. The fluid samples have analysed by Stratochem, a geochemical company based in Cairo.
  • Satellite Data. Interpretation completed in August 2007.
  • Magnetic Data. San Leon purchased the data from GeTech and completed the data merger.
  • Following successful completion of the Tarfaya seismic programme, Novaseis Sp.Z.o.o. were contracted to acquire new 2D seismic on Zag.In total 1,674 km of 2D seismic, largely on the eastern part of the licence area was acquired (Figure 7). This was completed in January 2012 and is the first seismic data ever acquired on this licence. Processing and interpretation was completed later in 2012.

Figure 7

Figure 7. 2011 Zag Basin Seismic Program (1,674 km of lines completed)

4. Terms

The Exploration and Exploitation (upon discovery) terms follow:
The Petroleum agreement will be concluded with the State prior to obtaining the Exploration Permit and upon a commercial discovery, the Exploitation Concession. To summarize:

The Exploration Permit lasts 8 years and is divided into three parts of 3.25 years, 2.5, and 2.25 years periods. Each Period is secured by a bank guarantee equal to 50% of the estimated value of the work program. The initial period ended in November 2012

The Exploitation Concession is granted for a commercially exploitable field discovery for a duration of 25 years with a possible extension of 10 years. Commitments include development, production and commercialization.

The Government working interest share of the Exploitation Concession is a maximum of 25%. ONHYM's interest is carried only during Exploration phase. The right holder will benefit from a 10 years income tax holiday.

The Government take-out in the case of Morocco is among the world’s most advantageous.

Tarfaya Basin

Licence name Gross acres Net acres Gross km2 Net km2 SLE share
Tarfaya 1,902,711 1,427,033 7,700 5,775 75%

Over recent years, Morocco has seen a flurry of exploration activity, and for good reason. Fiscal terms are very favourable, the area is underexplored, and there is a proven, working hydrocarbon system. The Company has identified prospects in three different plays in the Tarfaya Area; Jurassic, Triassic and Tertiary.

Tarfaya area geological background

The Tarfaya Area is a coastal basin developed in a passive margin. The Precambrian and Paleozoic basement is composed of very complex structures and is divided into horsts and grabens. On this, lies the syn-rift sequence of basal- Liassic, which is essentially composed of red clastic sediments: conglomerates, sandstones and clays associated with, in the North-Western region of the basin, lagoonal sediments. The post-rift mega sequence begins with the Lias-Dogger beds which are coincident with the opening of the Atlantic seaway and the progressive establishment of more marine environment with carbonate sedimentation. The second post-rift sequence, of essentially carbonates of Upper Jurassic age, correlates with the creation of a platform region to the South-East and an open marine region to the North-West. In the platform, elongated depocenters of NNE-SSW direction were developed while on the borders prograditional sequences of the Dogger were deposited in the western zone. In the Lower Cretaceous, carbonate sedimentation ceased and gave way to clastic sedimentation of a deltaic nature in a transgressive sea. This transgression was later followed by a regressive sequence in the Albian. The third post rift sequence is composed of an important silty-shaly marine deposit to the west and a coastal sandy continental conglomeratic deposit to the East. The fourth sequence corresponds to the major transgression that began in the Middle Albian reaching its maximum in the Cenomano Turonian. It is represented by marls, limy shales, bituminous shales, rich in organic matter and cherty phosphatic argillaceous limestones. During the Coniacian regression sedimentation remained only in shallow bays. At these locations such as Boukraa region, phosphate series were deposited during the Paleogene. This regression reached its maximum in the Oligocene following the Pyrenean orogeny. The uplift of the South-eastern area was the result of the major alpine orogeny during the Oligocene and Miocene. NNE-SSW to NE-SW structural trends, known in the Paleozoic formations, was found in Triassic.

TERTIARY PLAY

Within the Tarfaya block San Leon identified a Tertiary play. The structural interpretation of the area, based on the legacy 2D seismic lines, indicatedthe presence of four W-E trending channels. It is believed that the channels begin onshore and are observed continuing offshore into the Teredo/Glencore licence acreage. The trapping mechanism is believed to be stratigraphic within the sands of the Oligocene-Miocene channel fill with porosities ranging from 25% to 30%, similar to those encountered in the El-Aaiun 8-3 well. This well, drilled in the early 1970’s, discovered gas shows within the Middle and Upper Miocene intervals, with gas measurements up to C3. A thick interval of Tertiary shale (over 1300 m thickness) overlying Miocene channel sediments, provides a good regional seal. The high overpressure within the Tertiary sequence indicates possible seal effectiveness.

In September 2014, San Leon announced the completion of the Laayoune-4 well. The well was drilled in the Sahara region, 900 metres up-dip from the El-Aaiun 8-3 well which had multiple gas shows. The well (formerly known as El Aaiun-4) was drilled with Entrepose Drilling’s Cabot 750 rig, targeting Tertiary channel sandstones and with an expected total depth (TD) of around 2000 metres below rotary table (mBRT).

Gas shows were encountered within the reservoir section, whose gross thickness of 23 metres of sandstone and conglomerate was around 10 metres more than prognosed. Reservoir interval porosity was up to 18%, with some carbonate laminae. The reservoir was encountered some 100 metres more shallow to prognosis, and confirmed the geological concept of a thick sand channel system.

Elevated mud gas readings, including measurements up to C3 in the shallowest sands, coincided with the logged reservoir section. A gas and liquid kick was taken while drilling below the reservoir interval, leading to total depth being called early on the well at 1814 mBRT. The mud weight used was relatively heavy at 14 ppg (pounds per gallon), and no measurable mud losses were observed while drilling the target interval, providing good evidence for the overpressured nature of the formation.

The well was drilled on time, within budget and with no incidents.

Laayoune-4 has now been suspended, pending further studies and to allow future re-entry.

Based upon the results of the seismic, San Leon would consider the option of re-entering the Laayoune-4 well (including testing), drilling an additional well, or both.

Tarfaya-licence-boundary-area

JURASSIC PLAY

The Company has identified a prospect which is a progradational oolitic shoal. The Casa Mar prospect is a stratigraphic trap with two four-way dip closure components. The reservoir is believed to be oolitic shoals which are on the low-angle seaward deepening ramp formed in shallow, highly-agitated marine conditions. Upper Jurassic and Mid Jurassic tight limestone and shale layers are proven lateral and vertical seal in the offset wells. The source rock is expected to be Lower Jurassic (Toarcian, Pliensbachian) organic-rich marls and limestone. The Jurassic carbonate (oolitic shoal) play is being explored just offshore of San Leon’s licence, in the Tarfaya offshore area. The Cap Juby structure, a discovery in the Juby Maritime III Block offshore Morocco that was drilled by Esso in 1969, reported the presence of heavy oil (2377 bopd of 12° API oil from Upper Jurassic in well MO-2, and 75 bopd of 38° API oil in well MO-8 from Middle Jurassic carbonates). The Tarfaya-1 well, which is on trend with proposed San Leon’s Casa Mar prospect, indicated a presence of porous oolites with a net pay over 90m and maximum porosity of 22%. The oolitic sands in the Tarfaya-1 well were oil-bearing although breached by a Tertiary unconformity, which is not expected in the Casa Mar prospect location. San Leon has identified a potential drilling location for future upside. 

Casa Mar prospect

Tarfaya Basin 2

Casa Mar structural map

Tarfaya Basin 3

On trend with the Tarfaya-1 well and the Casa Mar prospect to the SW is the Casa Grande lead, a much larger prograding shoal package considered as a huge upside if the oolitic shoal play is proven at Casa Mar.

Seismic line through the Casa Grande lead

Tarfaya Basin 4

Casa Grande lead stratigraphic trap

Tarfaya Basin 5

TRIASSIC PLAY

A number of Upper Jurassic syn-rift leads have been identified on 2D in the north-eastern Tarfaya licence. Leads are primarily identified as stratigraphic pinch-outs, as a result of the extensional tectonic depositional environment. Hydrocarbons are believed to be sourced from Palaeozoic, or Intra-Triassic shales, with fluvial and aeolian red-beds acting as reservoir facies. The area is untested and has a large potential upside.

Triassic leads

Tarfaya Basin 6

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