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Ecopetrol Updates on US GoM Parmer Propect

Ecopetrol S.A., through its affiliate Ecopetrol America Inc., provided the results of the Parmer Prospect, deepwater Gulf of Mexico.

The Parmer prospect #1 is located on Green Canyon 867, at a depth of 18,900 ft (5,760 meters), which allowed for several pressure readings and the collection of several fluid samples from Miocene sands. The data indicate a column of approximately 240 ft (73 meters) of net condensate-rich gas pay, as prospect as one of 40 ft (12 meters) of net oil pay. In the coming months, Ecopetrol and its partners will reprocess 3-D seismic data and determine a comprehensive delimitation and development plan according to these results.

The two Parmer leases (GC 823 and GC 867) are located within the Green Canyon protraction area, at a depth of approximately 4,200 ft (1,280 meters) underwater. Each covers an area of 5,760 acres (23.3 square kilometers) and is located approximately 143 miles (230 km) from Louisiana.

Ecopetrol America has a 30% interest in the Parmer Prospect. Its partners are Stone Energy, and Apache that is the prospect’s operator.

The Parmer discovery is Ecopetrol’s second deepwater discovery in the Gulf of Mexico, one of the regions with the highest oil hydrocarbon potential in the world.

The results are expected to assist in Ecopetrol S.A.’s strategy to attain a production level of 1.0 million clean barrels of oil equivalent a day by 2015, and 1.3 million clean barrels by 2020.

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Pacific Rubiales Makes Gas Discovery in Colombia

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Pacific Rubiales Energy said today that it has discovered natural gas and condensate in the Cotorra-1X exploration well, drilled on the Guama Block in the Lower Magdalena basin.

The Company has 100% working interest in the block and is the operator.

Ronald Pantin, Chief Executive Officer of the Company commented: “this is an important exploration discovery for Pacific Rubiales and demonstrates the potential of both the Guama block and Lower Magdalena basin where the Company has a large exploration acreage position and is looking to increase its gas reserves to support its initiative to develop an LNG export market in the future.

The Cotorra-1X well was drilled as an exploratory well after an earlier exploration success on the block, the Pedernalito-1X well drilled in 2010. The well targeted Porquero Medio sands and silts of Miocene age, a low-permeability play successfully tested by Pedernalito-1X. Cotorra-1X was drilled to a total depth of 7210 feet in mid-January. The petrophysical evaluation showed a total of 40 feet of net pay, with average 20% porosity.

The well was perforated only in the deeper pay zone, across two intervals; leaving overlying pay zones untested for further evaluation.

After clean-up while flowing through a 1/2″ choke, Cotorra-1X reached a maximum gas flow rate of 7.5 MMcf/d and 370 bbl/d 56 degrees API condensate, followed by a three-stage isochronal and one extended flow test through 12/64″ choke which flowed at 2.6 MMcf/d and 121 bbl/d condensate at 3137 psi well head pressure.

During the month, the Company also completed drilling the Apamate-2X exploration well on its 100 percent owned and operated La Creciente Block. The well failed to test hydrocarbon flow at economic rates and was plugged and abandoned.

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Recap: Worldwide Field Development News Jan 13 – Jan 19, 2012

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This week the SubseaIQ team added 16 new projects and updated 32 projects. You can see all the updates made over any time period via the Project Update History search. The latest offshore field develoment news and activities are listed below for your convenience.

Africa – Other
Anadarko Successfully Appraises Lagosta Offshore Mozambique
Jan 17, 2012 – Anadarko Petroleum says its seventh well in the discovery area offshore Mozambique successfully appraised previous discoveries at Lagosta and Camarao. The Lagosta-2 appraisal well, located about 4.4 miles (7 kilometers) north of the Lagosta discovery and 5.3 miles (8.5 kilometers) south of the Camaro well, encountered 777 total net feet (237 meters) of natural gas pay in multiple zones. Anadarko says these results continue to support their recoverable resource estimates of 15 to 30-plus Tcf of natural gas in the discovery area, as well as provide additional information that will be incorporated into their models to help determine the optimal subsea development plans for the complex. The operator hopes to reach a final investment decision for this project in 2013. The Lagosta-2 appraisal well reached a total depth of about 14,223 feet (4,335 meters) in water depths of about 4,813 feet (1,467 meters) in the Offshore Area 1 of the Rovuma Basin. The partnership says it plans to preserve the Lagosta-2 well for future utilization during its planned drillstem testing program in the Windjammer, Barquentine and Lagosta complex. Once operations are complete, the Belford Dolphin (UDW drillship) will mobilize to drill the Lagosta-3 appraisal well.
Project Details: Lagosta
N. America – US GOM
McMoRan Begins Drilling in Blackbeard West
Jan 18, 2012 – McMoRan commenced exploratory drilling on the Blackbeard West No. 2 well on Nov. 25, 2011. The well is drilling below 11,700 feet (3,566 meters) with a proposed total depth of 26,000 feet. McMoRan is targeting Miocene-aged sands.
McMoRan to Flow Test Davy Jones No. 1
Jan 18, 2012 – McMoRan says completion activities of the Davy Jones No. 1 discovery well are at an advanced stage with flow testing expected in 1Q12. Initial production is expected shortly after a successful flow test. Furthermore, completion and flow testing of the Davy Jones No. 2 well are expected in the second half of 2012. Davy Jones is located on South Marsh Island Block 234 in 20 feet (6 meters) of water.
Project Details: Davy Jones
McMoRan Drills Deeper in Lafitte
Jan 18, 2012 – McMoRan says exploration results in the Lafitte well have indicated 211 net feet (64 meters) of possible productive sands, including 56 net feet (17 meters) in the Cris-R section of the Lower Miocene and 40 net feet (12 meters) in the Frio section. The well will be drilled below 32,400 feet (9,876 feet) to a proposed total depth of 33,000 feet (1,006 meters) to evaluate Oligocene and potential Eocene objectives. Lafitte is located on Eugene Island Block 223 in 140 feet (43 meters) of water.
Project Details: Lafitte
Africa – West
Rialto Energy Acquires 3D Data over Block CI-202
Jan 19, 2012 – Rialto Energy has completed a block-wide, full-fold 3D seismic survey covering 220,171 acres (891 square kilometers) over Block CI-202. Processing and interpretation of the newly acquired data will commence shortly and will provide the operator with a full suite of 3D data over the entire block. Rialto said that this will further refine existing interpretation and mapping of the exploration potential within the block through better definition and mapping of the multiple prospects and leads already identified. This data should provide a clear picture of the five existing discoveries and culminate in better definition of these existing resources. Rialto currently operates the CI‐202 block offshore Cote d’Ivoire, which contains the Gazelle Field. The field is the current focus of development with first production slated for 2012.
Project Details: Gazelle
Sonangol, TGS Reach Agreement for 3D Data Offshore Angola
Jan 18, 2012 – Sonangol and TGS have reached a final agreement for the acquisition of a 3D multi-client survey covering nearly 3 million acres (12,500 square kilometers) offshore Angola. The survey will initially commence over Blocks 36 and 37 in late January then continue over Block 35 with acquisition scheduled for completion in 3Q12. The high-potential pre-salt hydrocarbon play off the coast of Angola lies between 6,562 and 16,404 feet (2,000 and 5,000 meters) below sea level. TGS will process the 3D seismic data with final processed product expected by 4Q13.
Kosmos Strikes Again in Deepwater Tano Block Offshore Ghana
Jan 18, 2012 – Kosmos Energy has successfully appraised the Ntomme-2A well in the Deepwater Tano Block offshore Ghana, encountering significant quantities of light oil. The well was designed to test the potential of an oil leg beneath the previously-identified gas-condensate at Ntomme. Results of drilling, wireline logs and fluid samples indicate that the well encountered 148 feet (45 meters) of high-quality stacked reservoir sandstones, including 128 feet (39 meters) of 35 degree API gravity net oil pay. Pressure data from the well and the original discovery well suggests the potential of an oil column at Ntomme at about 410 feet (125 meters) below the gas-condensate accumulation. Ntomme-2A was drilled to an interim depth of 12,812 feet (3,905 meters) in a water depth of 5,675 feet (1,730 meters). Once drilling operations are completed, a drill stem test will be performed.
Project Details: Ntomme
Afren Makes Oil Discovery in Okoro East
Jan 17, 2012 – Afren has made a significant oil discovery in the Okoro East exploratory well offshore southeast Nigeria. The well encountered 549 feet (167 meters) true vertical thickness of net oil pay and 41 feet (12 meters) of net gas pay in excellent quality reservoir sands. The Okoro East exploration well was spud on Dec. 18 2011 and reached a total measured depth of 8,751 feet (2,667 meters) with the jackup Transocean Adriatic IX (350′ ILC). Afren says the well found oil in the Tertiary reservoir sands equivalent to those that have been developed and are in production at the Okoro main field, in addition to the deeper previously unexplored reservoirs. The discovery of significant pay in the previously unexplored deeper zones opens up further prospectivity at similar levels in the main Okoro field and elsewhere in the block, says the operator. Logging operations were completed and the well is now being prepared for testing, after which Afren will determine the optimal development of the discovery.
Asia – South
TNK-BP Commences Drilling Offshore Vietnam
Jan 19, 2012 – TNK-BP has commenced offshore drilling operations on the Lan Do field development project offshore Vietnam. The operator spud the Lan Do-2P well using the Ocean Monarch (UDW semisub). The Lan Do field contains two vertical subsea wells at a water depth of about 607 feet (185 meters). The sub-sea wells will connect to the Lan Tay Platform using a single 12-inch-diameter flow line. Gas production from Lan Do, which is scheduled to come on stream in the fourth quarter of this year, is expected to bring 2 Bcm of gas annually to sustain Block 06.1′s current production of 4.7 Bcm. TNK-BP acquired a 35 percent stake from BP and has become the operator of Block 06.1.
Asia – SouthEast
Lundin Touts Appraisal Results Offshore Malaysia
Jan 19, 2012 – Lundin Petroleum has appraised the Bertam-2 well in Production Sharing Contract PM307 offshore Peninsular Malaysia. Bertam-2 reached a total depth of 6,181 feet (1,884 meters) by the Offshore Courageous (350′ ILC) jackup. The objectives of the well were to appraise and test the Oligocene lower coastal plain sandstones of the PM307 PSC area. Discovered in 1995, the Bertam-1 well found oil in the K10 sandstone reservoir and flowed 34 degree API oil at a rate of 624 bopd on a short-term production test. The Bertam-2 well proved the continuity and quality of the K10 oil reservoir sandstone to the northeast of the Bertam-1 discovery well. Deeper sands that formed a secondary exploration target were confirmed to be water-bearing. The K10 reservoir sand was fully cored and logged. Preliminary interpretation indicates an oil interval with exceedingly large reservoir properties. During production testing, a stabilized flow rate of 756 bopd was achieved. Following testing, the well was plugged and abandoned and the rig demobilized. Bertam-2 is located to the northeast of the discovery well in 249 feet (76 meters) of water.
Project Details: Bertam
Rolls-Royce to Supply Gas Turbine, Compressor Equipment for Tapis Project
Jan 18, 2012 – Rolls-Royce has won an order for gas turbine and compression equipment for the Tapis oil and gas field, offshore Malaysia. The equipment will be utilized by ExxonMobil Exploration and Production Malaysia to expand and extend the production of the field. The order includes two Rolls-Royce RB211-GT61 gas turbines, each driving twin Rolls-Royce RCB and RBB multi-stage barrel gas compressors. Each gas turbine compressor set will produce 27MW of power, enough to deliver up to 390 MMcf/d of natural gas. The equipment is scheduled for delivery in 3Q12. The Rolls-Royce equipment will be installed at the Tapis enhanced oil recovery project featuring a central processing platform with a new integrated deck.
Australia
Chevron Hits Additional Gas Pay in Satyr-3 Well
Jan 19, 2012 – Chevron has successfully appraised the Satyr-3 well in the Exmouth Plateau area of the Carnarvon Basin, offshore Western Australia. The Satyr-3 well encountered about 243 feet (74 meters) of net gas pay. Satyr-3 reached a depth of 13,369 feet (4,075 meters) in a water depth of 3,688 feet (1,124 meters) by the Atwood Eagle (DW semisub). The well is located 113 miles (182 kilometers) north of Exmouth in the WA-374-P permit area.
Project Details: Greater Gorgon
Saipem Scores Gas Pipeline Gig for Ichthys Development
Jan 18, 2012 – Saipem signed an EPCI contract with INPEX for the gas export pipeline on the Ichthys LNG project offshore Australia. Saipem’s scope of work will include the engineering, procurement, construction and installation of 889 kilometers of a 42-inch-diameter subsea pipeline, in water depths of up to 902 feet (275 meters). The pipeline will connect the offshore complex to the onshore processing facility in Darwin. Offshore activities will be carried out during 2014 by the newly-built Castorone pipelay vessel. Gas from the field will undergo preliminary processing offshore to remove water and extract condensate. The Ichthys development is located on Block WA-285-P approximately 124 miles (200 kilometers) offshore Western Australia.
Project Details: Ichthys
Subsea 7 to Supply SURF Equipment for Fletcher, Finucane Development
Jan 17, 2012 – Santos granted Subsea 7 a US $60 million SURF contract for the Fletcher-Finucane development offshore Western Australia. The contract involves project management, engineering and installation of about 34 miles (55 kilometers) of flexible flowlines, more than 37 miles (60 kilometers) of umbilicals and associated structures to connect the wells to the existing Mutineer Exeter facilities. The contract also includes pre-commissioning activities and other associated services. Project management and engineering will begin immediately with offshore operations scheduled to commence late 2012.
Project Details: Fletcher/Finucane
Santos Sanctions Fletcher Finucane Oil Development
Jan 13, 2012 – Santos has sanctioned the $490 million Fletcher Finucane oil project in the Carnarvon Basin, offshore Western Australia. The project will be developed through a three-well subsea tie-back to the existing FPSO at Mutineer Exeter. First oil is slated for the second half of 2013 at an estimated average production of 15,000 bopd for the first 12 months.
Project Details: Fletcher/Finucane
Inpex, Total Give Nod to Ichthys Development
Jan 13, 2012 – Inpex and Total have greenlighted the Ichthys gas-export development offshore Australia. The $32.5B development is estimated to hold 12.8 Tcf of natural gas. Development plans for Ichthys include several subsea wells tied-back to a central floating offshore processing facility for gas, and an FPSO for condensate. Also, a 528-mile (850-kilometer) subsea pipeline will be constructed to transport the gas to a LNG processing plant in Blaydin Point, Darwin. The project is expected to produce 8.8 million tons (8 million metric tons) of LNG a year, with its first shipment being delivered in 2016.
Project Details: Ichthys
Mediterranean
San Leon Acquires Additional Seismic Data Offshore Albania
Jan 17, 2012 – San Leon Energy has received the first final processed volumes from its 207,569 acre (840-square kilometer) 3D seismic survey on its 100 percent-owned Durresi license in Albania. The survey was processed by Western Geophysical in London with a focus on detailed structural imaging, and incorporating relative amplitude preservation for the detection of subtle stratigraphic prospects on the flanks of the complex. The operator is currently processing the new 3D, as well as existing 2D seismic for the detection of stratigraphic traps. Initial results from the data have identified several large oil and gas prospects across the many petroleum systems that exist across the Durresi License, said the company. Plans to drill the first of a two-well exploration program on the block are being made for late 2012/2013.
Drilling Recommences at Leviathan-1
Jan 16, 2012 – Noble Energy has recommenced drilling at the Leviathan prospect. The Homer Ferrington (DW semisub) has arrived on location in the Rachel license drilling site and is expected to drill into the deeper targets of the well in the coming days. Drilling will continue where it left off in April 2011 for technical and operational reasons as reported in the past. Drilling is expected to last for three months. The Leviathan prospect is located in 5,361 feet (1,634 meters) of water at the Rachel and Amit license offshore Israel.
Project Details: Leviathan
S. America – Brazil
OGX Hits it Big at Fortaleza Prospect
Jan 16, 2012 – OGX has identified the presence of hydrocarbons in the Albian and Aptian sections of well 1-OGX-63-SPS in the BM-S-57 block, in the shallow waters of the Santos Basin. A hydrocarbon column of about 1,000 meters (3,280 feet) was encountered in Albian reservoirs with about 110 meters (360 feet) of net pay. The operator is still drilling the well but has already reached the Aptian section of the reservoir identifying hydrocarbons through a high-gas presence that resulted in a kick. OGX says this is under control. OGX-63 well, known as Fortaleza, is situated about 63 miles (102 kilometers) off Rio de Janeiro in a water depth of 509 feet (155 meters). The Ocean Quest (mid-water semisub) is drilling the well.
Project Details: Fortaleza
Europe – North Sea
Lundin Submits PDO for Luno Field
Jan 19, 2012 – Lundin Petroleum has submitted a plan for development and operation for the Luno field to the Norwegian Ministry of Petroleum and Energy. Lundin is in ongoing negotiations with Det norske, operator of license PL001B, in relation to a coordinated development solution for the Luno and nearby Draupne fields. The consortium expects an agreement to conclude shortly. The Luno development will incorporate both the Luno and Tellus discoveries, with first production expected in late 2015 with a forecast gross peak production of about 90,000 bopd. The capital cost of the Luno development including platform, pipelines and production wells are estimated at $4 billion. The Luno platform design capacity will accommodate in excess of 120,000 bopd when Draupne production is combined with the Luno field. The Luno PDO includes 15 wells drilled from a jackup rig, a processing platform on a jacket structure and export pipelines tied-back to existing infrastructure. Luno contains 186 MMboe of gross proved and probable reserves. The oil will be processed and transported in a new pipeline to the Grane area and further via the Grane oil pipeline to the Sture terminal. Lundin Petroleum has started placing contracts for the Luno development. A letter of intent has been awarded to Kvaerner, covering engineering, procurement and construction of the jacket for the Luno platform. A contract has been awarded to Rowan Companies for a jackup to drill the Luno development wells. Contracts for the topside and marine installations will be awarded soon. The Luno field is situated in PL 338 on Block 16/1 in the Norwegian sector of the North Sea in 354 feet (108 meters) of water.
Project Details: Luno
NPD Grants Det norske a Drilling Permit for Wildcat well
Jan 18, 2012 – The Norwegian Petroleum Directorate has granted Det norske a drilling permit for well 7/12-13S. Well 7/12-13 S will be drilled by the Maersk Guardian (350??? ILC) jackup in Production License 450. The area in the production license is located in the southern section of the North Sea, and comprises the southwestern part of block 2/4. The well will be drilled about six miles (nine kilometers) south of the Ula field. Det norske operates the license with a 75 percent interest; while Dana Petroleum holds the remaining stake.
Statoil Green Lights Dagny, Eirin Development
Jan 17, 2012 – Statoil and partners have selected a fixed platform development concept for the Dagny oil and gas discovery in the Norwegian sector of the North Sea, while the Eirin gas field is to be developed with a subsea solution. Gas from Dagny will be exported through a tie-back to the infrastructure on Sleipner East, while offshore loading into shuttle tankers is proposed for the oil. The seabed production installation on Eirin will be tied-back to the planned Dagny platform. Statoil says the chosen solution for Dagny and Eirin will now be secured, with the award of FEED contracts awarded shortly. Plans call for an investment decision to be taken next year, with production starting in 2016. Dagny is estimated to hold between 20 and 40 million Sm3 of recoverable oil equivalents. The Dagny oil field is located on Blocks 15/5 and 15/6 in the Norwegian North Sea in waters measuring 390 feet (119 meters).
Project Details: Dagny
Statoil Green Lights Dagny, Eirin Development
Jan 17, 2012 – Statoil and partners have selected a fixed platform development concept for the Dagny oil and gas discovery in the Norwegian sector of the North Sea, while the Eirin gas field is to be developed with a subsea solution. Gas from Dagny will be exported through a tie-back to the infrastructure on Sleipner East, while offshore loading into shuttle tankers is proposed for the oil. The seabed production installation on Eirin will be tied-back to the planned Dagny platform. Statoil says the chosen solution for Dagny and Eirin will now be secured, with the award of FEED contracts to occur shortly. Plans call for an investment decision to be taken next year, with production starting in 2016. Dagny is estimated to hold between 20 and 40 million Sm3 of recoverable oil equivalents. The Dagny oil field is located on Blocks 15/5 and 15/6 in the Norwegian North Sea in waters measuring 390 feet (119 meters).
Project Details: Dagny
RWE Dea Spuds Zidane-2 in North Sea
Jan 17, 2012 – RWE Dea has commenced exploratory drilling on the Zidane-2 well at Production License 435 in the Norwegian sector of the North Sea. The target of this well is to explore more gas reserves in the license. The West Alpha (mid-water semisub) is drilling the well to a vertical depth of about 15,748 feet (4,800 meters) in a water depth of 1,309 feet (399 meters). Drilling operations are expected to last 81 days with the possibility of an extension pending discovery.
Project Details: Zidane
Lundin Likely to Reduce Current Resource Estimates for Avaldsnes
Jan 16, 2012 – Lundin Petroleum has completed the 16/5-2S Avaldsnes appraisal well, located about 5.2 miles (8.5 kilometers) south of the discovery well 16/2-6 and two miles (four kilometers) south of the appraisal well 16/2-7. The objective of well 16/5-2S was to delineate the southern flank of the Avaldsnes discovery. Well 16/5-2S encountered a 49-foot (15-meter) Jurassic sequence of which the upper 26 feet (8 meters) has excellent reservoir quality. The top of the reservoir is deeper than expected, and below the oil water contact. Good hydrocarbon shows were observed below the oil water contact but were evaluated as not producable hydrocarbons. A comprehensive data acquisition program was performed, which including coring, wireline logging and fluid sampling. Results from the well will be incorporated into the current reservoir model, and a revised resource estimate will be released after the completion of the next appraisal well, 16/2-11. Well 16/5-2S is the first of an extensive Avaldsnes appraisal program compromising at least four wells in PL 501 during 2012. Lundin says this campaign will address key development planning uncertainties to ensure an efficient and optimal field development process for this discovery. The well was drilled to a total depth of 6,699 feet (2,042 meters) in a water depth of 364 feet (111 meters).
Project Details: Avaldsnes
Premier Oil Begins Drilling at East Fyne
Jan 16, 2012 – Premier Oil has started drilling operations on the East Fyne appraisal well in the UK sector of the North Sea Block 21/28a. Well 21/28a, located in the eastern portion of the Fyne field, is an Eocene Tay oil accumulation located southwest of, and on trend with, the producing NW Guillemot oil field.
Project Details: Fyne
Technip Wins Statoil Subsea Work
Jan 13, 2012 – Technip received two contracts for the Vilje South and Visund North developments in the North Sea in water depths of 394 and 1,263 feet (120 and 385 meters). These contracts cover welding and installation of a 6-mile-long (10-kilometer-long) production flowline; subsea equipment installation and tie-ins; and umbilical installation and tie-ins. Installation will occur in mid-2013.
Project Details: Alvheim
Statoil Shuts Snohvit Gas Field
Jan 13, 2012 – Statoil has shut production at the Snohvit gas field in the Barents Sea and LNG production at its Melkoya plant due to a ruptured fire water line. The rupture at the plant occurred Wednesday, January 13. The operator is working to eradicate the problem. Gas from the Snohvit field is transported to Melkoya for liquefaction and exports. Snohvit is located approximately 87 miles (140 kilometers) northwest of Hammerfest, Norway.
Project Details: Snohvit

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USA: McMoRan Encounters More Hydrocarbons at Lafitte Prospect

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McMoRan Exploration Co., a shallow water Gulf of Mexico exploration company, reported yesterday that its Lafitte ultra-deep prospect, which is located on Eugene Island Block 223 in approximately 140 feet of water, has encountered additional hydrocarbons.

The well has been  drilled to a true vertical depth of 29,756 feet and has been logged with wireline logs to 29,740 feet. The wireline log results indicated 56 net feet of hydrocarbon bearing sand over a 58 foot gross interval in the Cris-R section of the Lower  Miocene with good porosity. Flow testing will be required to confirm the ultimate hydrocarbon flow rates from this zone, which was full to base. McMoRan controls approximately 15,000 gross acres in the immediate area of Lafitte.

The new Cris-R sand interval combined with the 115 feet of potential net pay (250 gross feet) announced previously brings the total possible productive net sands to 171 feet in the Lafitte well. These results enhance the potential of McMoRan’s  other acreage in the Lafitte strategic area, including McMoRan’s Barataria and Captain Blood ultra-deep prospects. Barataria (10,000 gross acres) is located westsouthwest of Lafitte and Captain Blood (10,000 gross acres) is located immediately  south of Lafitte.

McMoRan plans to apply for a permit to deepen the Lafitte well to a proposed total depth of 32,000 feet to evaluate deeper Miocene and Oligocene objectives. Lafitte is McMoRan’s third ultra-deep prospect to encounter Miocene age sands below the salt weld on the GOM Shelf. McMoRan holds a 72.0 percent working interest and a 58.3 percent net revenue interest in Lafitte. Other working interest owners in Lafitte include Energy XXI (NASDAQ: EXXI) (18.0%) and Moncrief Offshore  LLC (10.0%).

McMoRan Exploration Co. is an independent public company engaged in the exploration, development and production of natural gas and oil in the shallow waters of the GOM Shelf and onshore in the Gulf Coast area.

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Bowleven Announces Drilling Success, Offshore Cameroon

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Bowleven, the West Africa focused oil and gas exploration group traded on AIM, on Friday (October 14) announced the discovery of oil at the Sapele-3 exploration well drilling in the Douala Basin, offshore Cameroon.

Sapele-3 drilling update

The Sapele-3 well is located circa 16 kilometers North West of Sapele-1 and circa thirteen kilometers North West of the D-lr wells. The well is drilling in water depths of approximately 30 meters.

The well was initially designed to target the shallower Miocene play including the reservoir interval previously encountered at Dl-r. Due to optimised well design it has also been possible to deepen the well into what is the Deep Omicron  equivalent interval encountered with previous Sapele wells.

Bowleven, as operator, provides updates for the reservoir intervals encountered at Sapele-3 below:

Deep Omicron interval (oil)

The well has encountered 11 meters of independently log evaluated hydrocarbon pay in high quality sandstone reservoirs within the Deep Omicron stratigraphic interval intersected by previous Sapele wells. In addition, a further 24 meters of  net sand was encountered, of which up to 11 meters is currently interpreted as having either a high residual hydrocarbon or a hydrocarbon bearing response from logs. Further evaluation to determine whether this is pay or not is pending.

Wireline logs indicate that the majority of reservoir has been encountered within two distinct packages within the upper part of the Deep Omicron interval that can be correlated to the earlier Sapele discovery wells. The logs also indicate high  net to gross ratios through these packages.

As the well is only two thirds of the way through the Deep Omicron interval and has encountered excellent quality oil bearing reservoir at current total depth (TD), the intention is to recommence drilling to the base of Deep Omicron. The  presence of light oil at current TD has been confirmed by sampling. Testing plans will be assessed on reaching final TD. The confirmed presence of oil in the Deep Omicron interval at Sapele-3, 16 kilometers from the original Deep Omicron discovery at Sapele-1, extends the currently mapped Deep Omicron fairway significantly Northwards into MLHP-6. Consequently a significant increase in current Deep Omicron in-place volumetrics is anticipated.

Miocene interval

At the shallower Miocene (Dl-r) equivalent interval target, a 7 meter high quality sandstone was encountered with a I meter gas-condensate column. The extent and size of the discovery is worthv of further evaluation.

Kevin Hart, Chief Executive of Bowleven plc commented:

“We are excited with results so far at Sapele-3. The Deep Omicron interval continues to deliver and the confirmed presence of oil and good quality reservoir at this location further emphasises the significance of this play within the Douala  Basin. All four Sapele wells drilled have now encountered oil within the Deep Omicron interval, thus reinforcing the geological model and highlighting the overall development and exploration potential of the fairway. This well has also now  shown that the Deep Omicron interval extends considerably beyond the currently mapped area which has significant implications in terms of both volumetrics and prospectivity potential on both block MLHP-5 and MLHP-6. In addition, the gas condensate discovery at the Dl-r interval is promising and warrants further evaluation.

The results at Sapele-3 represent another step towards our overarching strategy of converting resources to reserves whilst highlighting the extensive exploration potential in the basin. We look forward with eager anticipation to the further drilling planned at Sapele-3.”

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