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All articles in the Oil patch Sub-Sahara Section:


Frank Timis Threatens To Drill

LIBERIA

Will he or won’t he? That is the question, as Frank Timis, chairman of African Petroleum Corp., says his company plans to start drilling for oil off the coast of Liberia in March 2011.

APC has completed a seismic survey of its two exploration blocks, but Mr Timis looks like the kind of operative who would rather get other companies to operate and fund the E&P programme of an asset he has acquired.

Timis told the press that APC plans to bring a floating rig to drill two wells in the area, 48km off the coast and that drilling will cost $100 million.

This magazine’s guess is that March 2011 will come and APC still will not drill, unless one enthusiastic E&P company comes around to buy significant equity in those assets and goes ahead to drill. Since that had not happened by January 15, 2011, there’s no likelihood of APC being on the drill site off Liberia until late in the second quarter of 2011.

But announcements about plans to drill, such as the one that Mr Timis made in October 2010, only lead to pressure by the government of the country in which such assets are held. Right now, Mr Timis would be under pressure to proceed with his “drilling plans”. Liberia, for one, desperately wants “action” on exploitation of its resources. The West African nation is rebuilding its economy and infrastructure after a civil war that ended in 2003. Liberia is giving away its petroleum property to any company who can show sufficient enthusiasm to operate the property. That’s why the parliament approved an oil-exploration deal with California-based Chevron Corp. and Nigeria’s Oranto Petroleum Ltd(which has never spent money to drill a well anywhere).


Will SOCO’s Third Change The Tide?

SOCO International is making a third attempt at getting a discovery in the Democratic Republic of Congo (DRC). The company came up dry in the two earlier wells. The third, Bayingu-1, located on the same onshore Nganzi Block as the earlier two, will be the deepest test, to be drilled to approximately 2,520 meters and is expected to take 25 days to reach the target depth.

The first well, Nganga 1 was drilled to 2,175 metres Measured- Depth, reaching the basement as prognosed and encountering “approximately 500 metres of source rock with significant hydrocarbon shows and approximately 245 metres of good quality porous sand with an average porosity of ca. 17.5% in the primary target”. Petrophysical interpretations of the logs dismissed the reservoirs as water wet, but SOCO looked at the bright side: “The predicted lateral seal for the reservoir horizon was not present because of the change in the basin margin adjacent to the well location which can now be seen to have provided a local sediment entry point for sands”. The company decided that the next well, in a different part of the basin with a different margin geometry, was to be located further away from this localised sand and is not expected to be impacted by it. In spite of this prognosis, however the Kinganga Nyanya 1, drilled to 1,164 metres Measured Depth was also a commercial disappointment, Still, SOCO had an explanation for its second back to back dry hole: “The well drilled good source rock shales in the middle and Lower Bucomazi, interbedded with Lower Bucomazi sands.  It also encountered the target Lucula formation sands although these were not hydrocarbon bearing’ SOCO says. “There were oil shows in the Lower Bucomazi and the Chela formations. Log analysis indicated oil pay in the secondary target Chela formation sands. Although the well bore was not ideally situated to encounter the thickest part of the Chela sands, an abbreviated test was carried out to determine the reservoir characteristic. On test the sands were found to be tight”.

SOCO claims that in spite of the lack of commercial discoveries of the earlier two “they confirmed the presence of oil and provide valuable data that will be used in further evaluation of the area”.


XOM Returns To Shoot Yoho

The American major Tenders For 3D Survey APSDM In OML 104 Seven years after a carpet seismic coverage, spanning 1,230km2 full fold, ExxonMobil(XOM) is returning to the Oil Mining Lease(OML) 104, offshore Nigeria, for a Strategic Imaging Project. The work, this time, is largely a rigorous processing of the data acquired in 2003. The company is looking at a combination of anisotropic pre-stack depth migration APSDM, combined with advanced velocity model and tomographic techniques, “to improve fault sag and fault shadow imaging problems in OML 104 and ultimately reduce the structural deeper (>10,000ft) exploration leads as well as at Yoho and adjacent fields”. Fault surfaces will need to be depth interpreted and become surfaces that separate velocity contrasts within the model. Anisotropic parameters will need to be constrained by available well control and checkshots (Vl and Walkaway) as well as geological surfaces. “Finding the proper combination of depth imaging algorithms and model building will require some trial and error testing’ XOM declares.

ExxonMobil wants a collaborative effort in technology breakthrough with contractors that work in this kind of area. “Success will require strong collaboration between specialized experts from the contractor and MPN(the Nigerian shallow water subsidiary of ExxonMobil)”.

The 2003 vintage data was acquired in a 10 streamer dual source configuration in an East West direction, into 12.5 xline bins with 6km streamers with a1-8-7-m-fIip flop source yielding 80 fold. Due to surface obstructions in the area, some 1500m offset box-in-data was also acquired in 2003. Additional vintage streamer data(different shooting direction) will also be used to supplement near offset gaps around obstructions. The imaging programme area includes the entire 2003 3D survey extent(1230km2 full fold. “Based on technical and business needs, a priority area of ‘262 km2 full fold(”125 km2 image area) is planned to be branched off later in the velocity model building phase.

The entire workscope can then be broken down into three categories:

• High end preprocessing from navigation merged field taps. Noise mitigation, multiple suppression and signal enhancement are critical, particularly in fault shadow areas. Bin and regularlisation of data prior to migration.

• Iterative Anisotropic Velocity Model Building to accurately resolve lateral velocity contrasts across faults for the entire OML 104 block. Contractor must have a full suite of proven prestack depth migration algorithms (Kirchoff, Beam, WEM, RTM) as

well as proven tomography with ability to constrain input rays based on model surfaces. Contractor must have the ability to incorporate the geological surfaces and other geophysical data into the velocity/anisotropic model

• Hi end post-migration processing and noise reduction as required with a suite of angle stacks and specialized derivative volumes.


TANZANIA: Tullow Spuds Likonde-1 In The Rivuma

Tullow, the U.K listed, Africa focused operator, has spudded Likonde-1, a newfield wildcat well in its Ruvuma PSA in Tanzania. The well is expected to be drilled to a programmed total depth of 3,200 meters. Drilling time is estimated to be around two months, subject to any operational delays which can occur in a remote frontier area.

Aminex claims that the “Likonde prospect is a robust faulted rollover structure with the potential for 500 million barrels of oil in place and estimated P10 recoverable reserves in excess of 150 million barrels of oil”, risked by Aminex “at a 1 in 4 chance of success”. The Likonde-1 well will test multiple targets in the Tertiary, Cretaceous, and Permo-Trias Karoo intervals.

Pursuant to a recent farm-out, finalization which was announced on 15 December, interests in Likonde-1 are Tullow Oil (operator) 50%, Aminex 37.5% and Solo Oil PLC 12.5%.


Afren’s Ebok… Six Horizontal Wells Will Start the Drainage

Afren’s first phase development plan for Ebok field comprises five horizontal oil production wells in the D2 reservoir, one horizontal oil production well targeting the Dl reservoir and one water injection well in the central Fault Block 1 and Fault Block 2 areas of the field. All wells will be drilled from a single field location via a Well-head Support Structure (“WSS”) and mobile offshore production unit (“MOPU”). Fabrication of the WSS is complete and is in transit for delivery to the project. The company is in the process of finalising contract discussions on the production facilities. Associated gas produced will be utilised as fuel for the facilities’ power generation and as gas lift to assist well productivity.

Following completion of the initial development phase, the subsequent development phases will incorporate the full development of the D2 Southern Lobe, Dl reservoir (Fault Block 1 & 2 areas), and Fault Block West, whilst appraising the potential within the West Flank Qua Iboe structure, the 1)2 Upside Extension and the Fault Block North (cumulative total of 212 MMBBLS STOOIP and 66 MMBBLS recoverable), Afren’s report states.


NIGERIA; Afren Claims Substantial Reserves Increase in Ebok

‘Volumes Jump From 25 Million (predrill) To 116 Million Barrels After The Wells

Afren has reported a total gross hydrocarbon column of 107 ft in the appraisal well Ebok- 6 in the prolific south east shallow offshore Niger Delta. The company didn’t exactly report the net pay, but says that “greater than expected hydrocarbon column has led to an upgrade in D2SL volumetrics post Ebok-6”.

The new finds in three appraisal wells have shot up estimated recoverable volumes to ll6Million Barrels according to Afren. The wells were not tested.  The updated value, however,” is based on reservoir modelling work currently underway”, the report contended.

“Completion of Ebok-6 appraisal well represents the successful conclusion of the pre-development Ebok appraisal phase (Ebok-4, Ebok-5 and Ebok-6 wells)”, an Afren release noted.

The latest well has significant input in the claimed upsurge in reserves. The company’s prognosis of estimated recoverable reserves in Ebok 6 was eight (8) million barrels (MMBbls) . By the time the well was completed and the results came in, the recoverable reserves in  Ebok-6 recoverable reserves had increased to 23MMBBO.

The First phase of Ebok field Development underway with five horizontal oil production wells in the D2 reservoir.


GABON: M&P Flows 3,000BOPD In Omoueyi Wildcat

Maurel et Prom flowed 3,000 BOPD on 140/64” choke tests in OMGW-1, a newfield wildcat in Gabon. The well head pressure during the test was 550 psi, With a slightly lower choke size of 32/64”, the well flowed l,500BOPD. OMGW-1, located in the Omoueyi exploration permit, was drilled to a depth of 1,765 meters where it encountered the “Grès de base” play and saturated hydrocarbon reservoirs wire perforated.

Maurel et Prom said that the encountered reservoirs showed excellent permeability and porosity characteristics. The company is conducting an additional seismic survey which will be used to build a development scenario. A request for Exclusive Development Authorization will he submitted to the authorities in H1 2010. Prior to the request the company  will ask for a three-month production test.


CAMEROON: It’s 300 Ft. Gross at La-105

Victoria Oil & Gas (VOG) reached a total depth of 2,718 metres(8,920 feet) in La-l05 well, on the Logbagba field in Cameroon on January 1, 2010. As of the time of our going to press on January 15, 2010, the latest announcement was that the well was being logged, prior to its completion as a development well. VOG says that multiple gas-bearing sands were encountered at virgin pressures at depths between 1,800 metres and 2,500 metres, which can be correlated to those found and tested in the nearby well La-103. Well La-103 flowed at rates from 5 to 12 million cubic feet of gas per day from individual sands when drilled in 1956.

The data obtained while drilling La-105 showed in excess of 300 feet of gross pay and also indicated the presence of over-pressured shale gas in a significant interval. VOG expected to run a 7-inch liner will be run to isolate the sands for future testing and production. The company was expected to provide more detailed information on La- 105 and drilling of the next well at Logbaba, La-106 in due course. But Kevin Foo, VOG Chairman as very upbeat. “Notably, the presence of gas in the shale could add upside to previous management interpretations”.


Why Chevron Opts For Expensive 4D Shoot For Agbami

Seabird’s Hugin Explorer, meant to acquire 4D (Timelapse Three Dimensional) seismic data on the deepwater Agbami field off Nigeria, hadn’t started work as of mid October 2009, because the contract papers hadn’t been finalized. But officials of the state hydrocarbon company NNPC have explained why the Agbami 4D data acquisition will be the most expensive deepwater seismic data gathering on a single field in the country. “Difficulty in reservoir characterization in the Agbami field made operator Chevron opt for a seismic acquisition technology that lays emphasis on capture of as much data as possible”,  the NNPC officials indicate.

“The nodal analysis type of acquisition is far more expensive than conventional data acquisition used for Time lapse 3D seismic (or 4D) on similar Nigerian deepwater fields. including Bonga”, the country’s flagship deepwater pool. “But Chevron wanted to use this acquisition to get a new set of baseline parameters to which future time lapse 3D will be referenced”. Agbami field development was slowed down considerably by poor understanding of the reservoir, even as the field’s first oil date loomed. The shoot will take six to eight months to complete and will cover about 586 sq km of area.


Agip Missed The Target In Oberan 2

Agip missed the expected reservoir in Oberan -2, inspite of the large expectations created by the discovery well. Oberan -2 is located in the Agip operated Oil Mining Lease (OML)134. Delays in the approval of contract for the three dimensional seismic acquisition, led the company to go ahead and drill the appraisal well, taking advantage of an available rig. “They thought they had enough information with the existing Agip seismic data to drill the appraisal”, a source said. They were wrong. Lessons learned: “They are going to take their time with the third well, integrate all available data into the new 3D data on the structure and evaluate. Oberan 3 is not likely to be drilled until the second or third quarter 2010”.

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