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Kosmos Drills A Duster? That’s Huge

By Sully Manope, General correspondent

This prospect failed due to a lack of charge access

Kosmos Energy, widely regarded as a leading hydrocarbon finder in Africa’s frontier, has come up with a duster off Mauritania, the first in its recent history.

The Hippocampe-1 exploration well is supposed to be one of those probes outboard of the gas discoveries that Kosmos had been making off Mauritania. The search was for oil in as the company’s geoscientists described it: Large, out – board basin floor fan reservoirs trapped primarily stratigraphically, potentially charged vertically with oil / liquids.

Instead, the well “encountered well-developed reservoirs in both exploration targets but these proved to be water bearing”. Hippocampe-1 was drilled in approximately 2,600 meters of water in Block C-8.

Hippocampe-1 was designed to test Lower Cenomanian and Albian reservoirs charged from the deeper Valanginian-Neocomian source, the well was drilled to a total depth of 5,500 meters. The well will now be plugged and abandoned. Kosmos’ geoscientists believe that this prospect failed due to a lack of charge access in this part of the play fairway.

Andrew G. Inglis, Kosmos Energy’s chairman and chief executive officer, said: “Following on from our Yaakar discovery earlier this year, Hippocampe-1 is the second of four tests of independent prospects located in the outboard basin floor fan fairways in our Mauritania and Senegal acreage. Although the well did not encounter oil or gas, it has, together with Yaakar, confirmed the presence of quality cretaceous reservoir in the outboard basin floor fans, which contain multiple leads and prospects, more than 200 kilometers from the north to south through our blocks.

We are still in the early stages of opening this newly emerging basin and our forward drilling program remains unchanged given the independent nature of the prospect tests, in particular with regard to charge.”

The Ensco DS 12 drillship will now proceed as planned to Block C-12 offshore Mauritania to test the independent Lamantin oil prospect. The Lamantin prospect is located approximately 80 kilometers offshore and 180 kilometres northeast of Hippocampe in 2,185 meters of water. The prospect comprises Campanian age reservoirs charged from the shallow, immediately underlying, oil prone, oil mature Albian and Cenomanian-Turonian source rocks.

Kosmos holds rights in the C-6, C-8, C-12, C-13, and C-18 contract areas under production sharing contracts with the Government of Mauritania’s Société Mauritanienne Des Hydrocarbures et de Patrimoine Minier (SMHPM). The blocks range in water depth between 100 and 3,000 meters, and have combined acreage of over 40,000 square kilometres gross. Kosmos is the exploration operator of Block C-8 with 28percent equity and is joined by its partners BP 62% and SMPHM (10%).


SDX Expects To Finalise KSR-14 in Mid-October

SDX Energy expects to announce the drilling results of KSR-14 in mid-October. The probe is the first of a nine well drilling programme on the Company’s Sebou, Gharb Centre and Lalla Mimouna permits in Morocco.
KSR-14 is a development well and it is located on the Sebou permit.
“On success, the well will be completed, flow tested and connected to the existing infrastructure. These activities are anticipated to be carried out within 30 days of the drilling rig departing the location”, SDX officials say.
The nine well drilling campaign on three permits follows extensive technical work from which the optimal drilling locations were identified, SDX claims. The London headquartered, Toronto and AIM listed explorer is targeting an increase in its local gas sales volumes in Morocco by up to 50% and an increase in its reserves by more than 100% through this drilling campaign.


ENI Is Ready For Its Debut Moroccan Drilling

By Toyin Akinosho

Italian giant ENI has secured the Saipem 12000, a sixth generation ultra-deepwater drillship, for a drilling programme to include a one-well drilling slot in Rabat Deep Offshore in Morocco. It is currently anticipated that the rig will arrive on location in the latter part of Q1 2018 and that the drilling of the RD-1 well on the JP-1 prospect will commence shortly thereafter.

ENI operates the Rabat Deep Offshore licence with 40%. Its partners include Australian Woodside 25%, Morocco’s state hydrocarbon company ONHYM 25%, and the London listed minnow Chariot 10%).

The JP-1 prospect is a large, four-way dip closed structure of approximately 200 square km areal extent, with Jurassic carbonate primary reservoir objectives which, Chariot claims, has an “independently audited gross mean prospective resource estimate of 768MMbbls”.

ENI purchased its 40% on the asset from Chariot, who it is partnering Chariot in return for a capped carry on the drilling of the JP-1 prospect as well as a carry on other geological and administrative costs relating to Rabat Deep Offshore and a recovery of Chariot’s investment prior to farm-out.


Cairn’s SNE North-1 Is Unimpressive, But Better than the Last Probe

By Fred Akanni, Editor

Results of the SNE North-1, Cairn Energy’s most recent probe offshore Senegal, are better than what came out of the FAN South-1 exploration well drilled just slightly earlier.

But the preliminary analysis of the hydrocarbon footage suggests that the reservoirs are not as developed as the equivalent encountered in offset wells SNE 1 and 2.

What is encountered in the primary objective is not oil, but condensate, of 11 metre net thickness. Only four metres of oil was identified in the secondary objective, which had not been probed anywhere else in the sequence and as such could be an upside. “The well encountered oil in the deeper secondary objective, in a separate accumulation to the SNE field”, Cairn says in their release.

The entire gross hydrocarbon interval is however 24 metres thick, which is quite thin compared with 97 metre (average) gross hydrocarbon interval encountered in the same sequence in SNE 1 and 2.

If these are the same reservoirs, as in SNE 1 and SNE 2, then SNE North 1 is not adding any much volume to what’s already documented. If they are not the same reservoirs, however, the fact that they are thinner reservoirs does not preclude them for being better gushers than thicker reservoirs encountered in the offset wells.

SNE North-1 is being plugged and abandoned and the Stena DrillMAX rig will be released.

Cairn is trying to sound optimistic about this result, the second consecutive not-so-great result in the Senegal campaign. “Further work is being undertaken to establish the potential commerciality of this discovery and to integrate the results with the block wide data gathered to date”, the company says. “The well result has positive implications for further hydrocarbon potential to the north of the structural trend containing the SNE field and SNE North-1 discovery well, as well as for broader exploration potential in the permit.

SNE North-1 is located in ~900 metres (m) water depth, ~ 90 kilometres offshore in the Sangomar Deep Offshore block and ~15km north of the SNE-1 discovery. The well reached a Total Depth (TD) of 2,837m. Operations have again been safely and successfully completed ahead of schedule and under budget, following drilling and logging.

“A full set of oil, water and gas samples was recovered to the surface. After completing conventional logging, a series of Modular Formation Dynamic Testing (MDT) mini-fracs were obtained across the reservoir section to help calibrate the geo- mechanical model of the SNE field and aid development well design.

“This marks the end of the five well 2017 drilling campaign”, Cairn says. The operator and its partners are reviewing the potential for further exploration drilling operations in 2018, within the Rufisque, Sangomar and Sangomar Deep Production Sharing Contract area.


SD-1X Flow Rates Exceed Expectations

Operator aims to bring discovery to commercial operation as soon as possible

SDX Energy says the initial well test results of the SD-1X well has exceeded its own expectations as operator.
The well is SDX Energy’s first probe in the South Disouq licence in Egypt where the Company has a 55% Operated working interest.

“SD-1X has successfully flowed dry natural gas at a stabilised rate of 25.8 MMscf/d on a 48/64″ choke”, the company says in a release. “This flow rate exceeded initial expectations and was limited by the surface facilities put in place to test the well”.

The well was drilled to a total depth of 7,777ft, and encountered 82 ft. of net pay with an average porosity of 25% in the Abu-Madi section.

SDX-1 has now been shut in for an initial build-up after which a series of additional flowing periods will be conducted and fluid samples taken. The results from the well testing programme will be integrated into the on-going reserve evaluation work.

The results of that exercise will then be incorporated into an early development plan proposal for discussion with our partners and the authority. This information will be included in a future release to the market over the summer.

Working with its partners, SDX will now aim to bring the discovery into commercial production as soon as possible.


In Senegal, The Aptian Carbonates Are Not Commercial

By Sully Manope, in Dakar

Cairn Energy has failed to find a commercial pool of hydrocarbon in the deeper, older reservoirs below the play it encountered in its 2014 discovery of the SNE field in Senegal.

The VR-1 well was loudly applauded in the media as a bigger success than most of the five appraisals of the SNE-1 discovery.” It is a significant step out, some 5 km west from the line of wells drilled to date, including the SNE-1 discovery”, Cairn says. “The results will be useful for the planning of the first phase of development – the lower 500 series reservoirs are the better connected, more tabular, highly productive sands, where water-flooding should yield recovery factors of 30% or more”. 
But while VR-1 was primarily meant to evaluate the 500 series reservoirs already confirmed elsewhere, its secondary objective was to test the carbonates below those sands.

“The deeper carbonate exploration targets were encountered as expected with indications of hydrocarbons at the base of the well in tight formation that is not currently viewed as commercial”, the company says in a release. 
A significant amount of new stratigraphic and log data has been recorded which will be incorporated into the regional geological model” Still, the company is encouraged that the appraisal results from VR-1 are very encouraging, as the well result confirms the predictability of the mapped reservoir over a wide area giving confidence to the reservoir engineering models”


BP Pumps Up Egypt’s Gas Volume

By Mohammed Jetutu, in Cairo
 
With the new discovery in the North Damietta Block in Egypt’s East Nile Delta, announced March 27, 2017, BP has provided more reason for Egypt to pull out of the club of gas importers.

Since 2015, the country has been importing LNG to meet the shortfall in domestic production.

Africa’s largest domestic gas market consumes 2Tcf of gas a year, or 5.5Bcf every day, most of it going to fuel 70% of its 30,000MW electricity production capacity.
In the last three years, however, a string of discoveries, aided by the leap in domestic gas price to as high as $5.9 per thousand cubic feet (Mscf), has been made by international oil companies in the country.

BP’s Qattameya Shallow-1 discovery, arrives right in the middle of two of the company’s most ambitious gas monetization developments. The Atoll Phase One project, in the same North Damietta Block as the Qattameya Shallow-1 discovery, is an early production scheme that will bring up to 300 million cubic feet a day (MMscf/d) gross of gas to the Egyptian domestic gas market starting in the first half of 2018.The Western Nile Delta project will develop five trillion cubic feet (5Tcf) of gas resources. Peak production is expected to be 1.74Bcf/d, by 2020. BP is also currently appraising the Salamat discovery, in the North Damietta concession.

Qattameya Shallow-1 was drilled to a total depth of 1,961 metres in water depth of approximately 108 metres using the El Qaher II jack-up rig. The wireline logs, pressure data and fluid samples confirmed the presence of 37 metres of net gas pay in high quality Pliocene sandstones. Options to tie the discovery back to nearby infrastructure are being studied.

Qattameya Shallow-1 well is located 60 kilometres north of Damietta city, 30 kilometres south west of Salamat and only 35 kilometres to the west of Ha’py offshore facilities. BP has 100% equity in the discovery.
 


SDX Moves to Drill SD 1X

London headquartered SDX is mobilising the Sino-Tharwa 6 drilling rig to the location of South Disouq (SD)1X, its first well in the South Disouq licence onshore.  

The Company anticipates drilling to commence at the SD-1X location by March 20, 2017.
SDX is 55% operator of the South Disouq licence, an exploration asset located onshore central Nile Delta. IPR Group of companies holds the remaining 45%.

The South Disouq concession spreads over 1,275 sq km and is estimated to contain 1.3 TCF of resource potential (P10). The concession is located within the prolific Abu Madi – Baltim trend which to date consists of 10 discoveries containing 6.3 TCF of gas and 100 MMBO of liquids.

The company also has a working interest in two producing properties (50% North West Gemsa & 50% Meseda) located onshore in Egypt’s Eastern Desert, adjacent to the Gulf of Suez.


Confirmed: ENI Is On Rampage in the North

By Mohammed Jetutu, in Cairo 

Italian major ENI is clearly on the run with the ball. Days after it reported reaching production of 700 Million cubic feet of gas per day on a field in Egypt’s western Nile,  it has released results indicating two thousand barrels of oil per day from drill stem test in Laarich East-1, onshore Tunisia, a site of low exploration and less than trickle of discoveries. This is coming at a time when the Milan based company has declared its fifth well on the Zohr discovery, as “confirming the field’s estimated potential of 30 Trillion cubic feet”. The Tunisian well has since been completed on hooked on to production.

ENI has also signaled it will soon bring a rig to drill in deepwater Morocco, a province that has played host to five dusters in the last three years.

ENI returned to drilling in Tunisia,largely unannounced,in June 2016. Laarich East-1, located in the MLD (Makhrouga-Laarich-Debbech) license, is five kilometers east of the oil treatment centre in a concession where the company  owns a 50% stake and the Tunisian state company ETAP the remaining 50%.

ENI reached the final depth of 4,111 meters, discovering hydrocarbons in sandstone layers of Silurian and Ordovician age. “Production tests confirmed the upside potential of the concession identified through the recent three-dimensional geophysical survey carried out on the permit’, ENI says in a release.

“In the meantime, exploration activities in Tunisia are continuing with the drilling of additional prospects, which have been already identified on 3D Seismic”, the company adds.

“The drilling of Laarich East-1 is part of ENI’s near field strategy, adopted to cope with the low oil price environment, and consisting in conducting exploration activities in the proximity of existing infrastructures with available spare capacity. In case of a discovery, this strategy allows for the optimization of development costs and competitive time to market for production start-up”.

 


Ain Tsila Development: First Well Done, 23 More to Go

Irish minnow Petroceltic has released a “so far, so good” report of the first of 24 development wells on the Ain Tsila field.  “Wireline logging results from the AT-10 well indicate that reservoir quality is in line with the pre-drill prognosis, with an expected initial off-take rate comparable to AT-1 and AT-8 wells,  each of which delivered flow rates in excess of 30 MMscf/d on test”, the company says. “Well test results will be confirmed later in 2016 when planned batch completion, stimulation and testing activities are undertaken”.

AT-10 is located in the north of the field approximately 3.4 km from the field discovery well AT-1, and 2.0 km from the appraisal well AT-8. The 24 new development wells are expected to establish and maintain the currently approved annual average wet gas plateau rate of 355 MMscf/d.

AT-10 began drilling on 21 February 2016 and on 31 March 2016 it reached a total depth of 2005m MD, with a planned 61m penetration of a fully gas and condensate bearing Ordovician formation.

The Sinopec Rig is now moving to the AT-13 development well, located in the north of the field approximately 1.8 km from the appraisal well AT-8, and 6.1 km from the appraisal well AT-1.

AT-13 is targeting the Ordovician reservoir and will be drilled as a vertical well to a planned total depth of 2004m MD.

Petroceltic holds a 38.25% interest, Sonatrach a 43.375% interest, and Enel an 18.375% interest in the Isarene PSC. Petroceltic continues to benefit from a carry of its development costs in respect of Ain Tsila following the completion of the sale of an 18.375% interest to Sonatrach in July 2014.

© 2017 Festac News Press Ltd..

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