So based on the info from the stratic website on the acquired lease, who wants to hazard a value on it, sp wise?
Come on t4p, I reckon your lurking?
Tunisia
Kerkouane Permit including the Dougga gas condensate discovery
Stratic holds a 100% interest in the Kerkouane permit located partly onshore, but principally offshore the north-western coast of Tunisia. The permit covers an area of approximately 6,720 km2 and is delineated by the Tunisia-Italy maritime border and is contiguous with Stratic�s Pantelleria Island acreage in permit GR 15 PU in Italian waters. The regional setting of the Kerkouane and many of its defining characteristics are similar to those described for Stratic�s Pantelleria Island acreage elsewhere in this report. Water depths over the permit range from zero (onshore element) to 700 meters.
The Kerkouane permit was held by Shell in the late 1970s and early 1980s and more recently by Anschutz. It was licensed to Grove in January 2006 under a two year term with a work obligation of 200 kms of new 2D seismic together with a well to be drilled to a depth of 2500 meters. The permit is subject to production sharing terms which provide for an annual cost recovery of 40% for oil (45% for gas), with a profit oil split varying from 35% to 15% depending on a recovery factor variation, in steps, from 1 times to 2.3 times. All royalties and corporate taxes are paid by ETAP, the state participant under the production sharing contract.
There is a wide array of old vintage seismic data covering parts of the Kerkouane Block. Most of this data is not available in digital format and some is not available as usable paper copies. Three modern seismic data sets are available over the permit. In 2000 Forest Oil acquired 404 kms of 2D marine data in seven lines and, in 2001, Anschutz acquired 1,284 kms of 2D seismic data. The most recent data set was acquired by Grove in 2005 and allowed correlation of data between a number of nearby accumulations and prospects
A total of seven wells were drilled by Shell in the region in the period July 1979 to February 1984. Of the four wells drilled on Kerkouane, two were plugged and abandoned without shows and two wells yielded gas flows on test. The most promising well, Dougga-1, was drilled in 1981 to test a fault closed NNE plunging anticlinal structure with the main objective in the Middle Miocene Birsa Formation. The Abiod (an Upper Cretaceous carbonate) was a secondary objective. The well reached TD at a depth of 3,640 meters in the Jurassic Nara Formation.
The well encountered a thick Tertiary sequence with good reservoir sands in the Birsa formation, but the gas bearing sands contained almost pure CO2. No hydrocarbon indications or reservoir rocks were detected in the Fortuna, Bou Dabous or Ain Grab formations, but a hydrocarbon gas bearing sequence was found from the Cretaceous Abiod formation downwards. Further down gas samples collected in the Jurassic Nara formation again indicated a high percentage of CO2 (>95%).
Gas was recovered in RFT sample chambers at several levels from 2,200 m and below but with high and erratic percentages of CO2. One production test was run over the Abiod Formation and flowed wet gas at rates of 1 to 2 mmscfd with condensate at 80 bbl/mmscf; the gas contained 30% CO2. An FIT sample taken at 1,866 meters collected gas with a high CO2 content. Seals were reported to be leaking on the test tools during this test. Production data from other fields that produce from the Abiod formation shows that effective permeabilities can be much higher than the base rock permeability because the fluids migrate through networks of micro fractures and visible fractures.
The composite well log for Dougga suggests that the higher Birsa sands at about 1,800m have an almost identical log character to the Tazerka oil sands. These sands have never been production tested at Dougga and represent a significant upside potential for Dougga.
The closest offset well data available is for Tazerka-1, drilled in July 1979, some 25 kms south east of Dougga-1, where the Abiod formation was 94 meters thick and was tested at rates of 12.5 mmscfd gas and 921 bbl/d condensate (ie, a condensate gas ratio of approximately 74 bbl/mmscf). The well site fluids analysis suggested:
Gas: 18.5mol% hydrocarbons in the gas, 47mol% CO2, 100 ppm H2S
The Sidi El Kilani field also produces from Abiod formation, but it is an oil field and it produces almost exclusively from a fracture network with very little contribution from the bulk rock itself. The Sidid El Kilani wells tend to quickly develop high water cuts as formation water travels through the fracture matrix. The Miskar field, which is over 100 miles to the South of Dougga-1, has been producing from the Abiod formation since 1996. Key characteristics are: Net to Gross 86%, Porosity 25%, Sw 15%, CGR 20bbl/MMCF, and Gas Composition: 16.9% N2, 13.4% CO2, 0.08% H2S.
Dougga is a moderately faulted anticlinal high with a distinct NW-SE local fault trend, at the 2,600 m depth contour the feature has approximately 30 km2 of closure and it exhibits 200 meters of vertical relief. Dougga-1 was drilled close to the crest of the high and intersected several gas columns.
Development viability studies for the Dougga discovery are currently underway. Given the relatively deep water depth local to Dougga, and the H2S and high CO2 content in the product streams necessitating complex gas processing facilities, there are essentially two development options: process the fluids offshore on an FPSO or process the fluids onshore. Wellhead fluids would be a multi-phase mix of gas, condensate and produced water. The fluids would be rich in H2S and CO2, water saturated and extremely corrosive. They would likely present significant flow assurance challenges: slugging, hydrate formation, corrosion and erosion.
To process the Dougga fluids onshore would require a corrosion resistance pipeline at least 45 kms long. Once onshore the plant would need to be sited away from human habitation, owing to the hazardous nature of the fluids involved. The flow assurance issues described above would affect the choice of pipeline size, the range of feasible pipeline operating pressures and limit scope for even quite gradual changes in flow rate during operation. There is insufficient data available at this stage to determine whether an onshore development scheme is feasible technically or economically.
Processing Dougga fluids offshore, using a converted LPG carrier as an FPSO, considerably reduces the flow assurance challenges and facilitates the sale of each potential liquid product stream separately. Depending on the level of offshore processing, the gas pipeline to shore could be fabricated from standard and therefore cheaper carbon steel rather than corrosion resistant alloy. Regulatory approvals for disposal of produced water and flaring of acid gas would likely be easier to obtain for an offshore development.
Until further work on all of these areas of uncertainty is completed it is impossible to determine with any degree of certainty whether a viable economic development of Dougga can be achieved. Stratic intends to seek an extension of the current licensing term to enable further studies to be carried out before committing to a further work program. The likely next step will involve the drilling an appraisal well on the Dougga discovery to test the productivity of the Abiod reservoir but this would only be undertaken if the permit is extended, a suitable rig sourced and a partner identified to mitigate risk.
There are a number of exploration leads in the Kerkouane block that have been identified in addition to the Dougga discovery, but they are based largely on relatively sparse, low quality, vintage seismic data. However, it is likely that at least some of these leads will benefit from modern seismic coverage and might be upgraded to drillable prospects in due course. The main leads are Cap Bon Mare, Carthage, Kerkoune and Menzel Temime.
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