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Gulf of Mexico: MMR’S Moffett Keeps His Eyes on the Prize at Davy Jones

Joan Lappin, Contributor

Greetings from Denver and the EnerCOMConference where McMoRan presented on 8/13. It’s interesting to observe that as we really near the end of problem solving at Davy Jones, investors are so shell shocked they can’t believe the flow test might really happen soon. Many cannot see the forest for the trees or the enormity of this Shallow Water Ultra Deep play vs. the limited prospects of the shale plays they love so dearly. Most shale wells are unimaginative step out wells a short distance away from other known discoveries. Many of the public shale players are recent arrivals in those plays and are paying the price for being followers, not leaders. Their potential returns on invested capital are tiny compared to the potential enormity of the Shallow Water Ultra Deep which can totally transform the U.S. energy picture for the future.

Add to that MMR’s Main Pass Energy Hub where it has reapplied for an export permit to use this facility 20 miles offshore to export hydrocarbons to other parts of the world where gas prices are far above the current <$3 in the United States.

Nobody on earth wanted to have flow tested this well prior to this EnerCOM energy gathering more than Moffett so that this might have been the finest champagne party of this century. Instead, after almost a year of delays, Davy Jones is still not giving up its bounty without a final fight. So, the flow test is still to come.

Jim Bob Moffett stood resolutely in the break out session and at the McMoRan dinner last night and patiently answered the same questions again and again. What about your balance sheet? Aren’t you going to run out of money? Do you honestly think you will have a successful flow test? Is there really permeability in these rocks? How big is this play? Really? Ironically, the well wants to flow so much that the latest problems have revolved around containing the flow, not encouraging it.

As future well completions in the Shallow Water Ultra Deep move forward, rest assured there will be a whole series of protocols that will be standard operating procedure. For one thing, wells will never again be designed to have tiny pipe at the bottom of the hole, making all efforts difficult because there is no room to maneuver tools and equipment. Wells surely won’t be using Schlumberger’s remote control small guns to perforate the casing. The folks at BOEMRE won’t be requiring the interruption of a flow test to move the rig back off the well. And wells will have packers routinely placed at the bottom of the production tubing so that no matter what comes flowing up after perforation of the well, it can easily be contained and controlled. Moffett takes responsibility on himself for not foreseeing that the original multiple O ring type assembly currently being pulled out of the hole would have to contain a far larger perforation project than originally conceived for one zone at a time instead of what resulted from perforating all zones at once. These recent completion activities and “redos” at Davy have cost the group another $70 million. You can’t sue the Government but one wonders what culpability might be laid at Schlumberger’s feet when all the dust settles.

Halliburton’s Boots and Coots pressure control experts are finally off the well. So we can presume that the final preparations for the flow test are now underway. If you look at Moffett’s latest presentations, I believe the slides and cartoons are aimed not at the public markets but at the huge investors who will soon be coming out of the woodwork to turn this into a full blown commercial development to rival the biggest and most important energy projects in the history of the U.S. oil and gas industry.

Many of the folks in the room, some of whom control or influence vast pools of money, don’t seem to see the forest for the trees or grasp what is coming about here. At the conference, if you go into the presentation rooms of those producing from shale plays onshore in the various parts of the country, there is standing room only, just as there was last year. Those investors don’t seem too concerned that shale requires $5-7 gas to be profitable in the present $3 world for natural gas prices. They don’t seem afraid of the write downs of reserve values that are coming at the end of the year. They only seem to focus on the $300 million + cost of Davy Jones and are sure that it will never produce economically. They don’t understand that at some point DJ became a science experiment for the entire play and its proof of concept.

A major topic at dinner was about the cost of future wells. Moffett seems particularly happy with future use of expandable liner to limit the starting size of pipe that must be used. He thinks future wells, particularly those on land at Lineham Creek (Chevron is the operator) and at its new huge Highlander prospect onshore where it will be the operator, can be brought in for $75 million per well. Everything on land is much cheaper from land rigs, or even barge rigs in the swamp areas where there is less than 10 feet of water, to not needing support helicopters and delivery boats. Also, onshore with some of the targeted formations closer to the surface, the support costs are much less, too. Even offshore wells will be far cheaper going forward even if more than $100 million.

Energy XXI, MMR’s junior partner, and Tex Moncrief are reportedly on pins and needles with the rest of us but with no wavering in their conviction about the Ultra Deep. Fortunes are made with patience and by leading, not following, the pack. This group fits that description in spades. Moncrief loves to tell the story of getting hooked on the oil patch when out with his Dad as a young boy in a pair of rubber boots watching a well start to gush oil into the air. Davy is trying to gush, too. It shouldn’t be long now until all the believers get their reward, including the public shareholders.

Joan E. Lappin CFA Gramercy Capital Mgt. Corp.

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USA: McMoran Reports Flare from Davy Jones

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McMoRan Exploration Co. announced yesterday continuing progress to flow test the Davy Jones No. 1 well on South Marsh Island Block 230. As previously reported, McMoRan saw positive pressure response from the Wilcox “D” sand which was perforated on March 24, 2012.

On March 26, 2012, McMoRan attempted to perforate the Wilcox “C” sand. As the perforating gun was being removed from the hole, the well began to flow. When the gun was brought to the surface, it was determined that the gun did not fire in the Wilcox “C” sand from what appears to be a simple disconnection of the detonator cord. McMoRan plans to use a new perforating gun to complete the testing of the Wilcox “C” sand.

Currently, the test is ongoing from only the Wilcox “D” sand, which resulted in the flare. The flow from the “D” sand is being affected by considerable debris in the 5 inch liner, from what McMoRan believes to be residual drilling fluid from drilling of the well. Results of a clean flow test, as opposed to the current test hampered by debris, will be announced as further progress is achieved and flow rates are measurable. McMoRan will provide updates as completion operations progress.

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Davy Jones involves a large ultra-deep structure encompassing four OCS lease blocks (20,000 acres). McMoRan is the operator and holds a 63.4 percent working interest and a 50.2 percent net revenue interest in Davy Jones. Other working interest owners in Davy Jones include: Energy XXI (15.8%), JX Nippon Oil Exploration (Gulf) Limited (12%) and Moncrief Offshore LLC (8.8%).

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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A Little Bit Louder Now, Chevron Starts To Shout About Davy Jones And The Ultra Deep

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Joan Lappin, Contributor

I can’t stop hearing that famous Isley Brothers song Shout in my head as I write this post: “A little bit louder now, a little bit LOUDER now, A LITTLE BIT LOUDER NOW.”    About a year ago, speaking at a popular oil and gas conference Chevron tipped its hat to McMoRan’s Jim Bob Moffett and his work in the Gulf of Mexico Shallow Water Ultra Deep (SWUD) play that has been ongoing for more than five years.  That event was truly noteworthy because major oil companies rarely, if ever, acknowledge a little player like MMR as being out front and leading the wave on any important new geological play.  Chevron has recently promoted the Shallow Water Gulf of  Mexico to one of its top three areas of geologic focus around the world.  And it is becoming more vocal about its involvement.

Chevron is no longer whispering. In fact, there is a crescendo building in what CVX is saying about the Gulf of Mexico and what it is doing itself and with partners, both onshore and offshore.  Many MMR watchers know that at 2011 year’s end, Chevron spud a well onshore in Cameron Parish, LA called Lineham Creek. It has a proposed total depth of 29,000 feet targeting the Eocene and Paleocene objectives below the salt weld. This is Chevron’s well in the Rockefeller Preserve, land that was donated to the State of Louisiana years ago. However, the royalty rights on the land were retained and passed to Chevron.

In recent months, Chevron invited MMR to participate in the Lineham well and Moffett agreed as long as his Ultra Deep partners were also included in the project. What’s significant is that giant Chevron wanted MMR to join it in this project as an equal partner. After Moffett made sure his partners were along for the ride:  MMR is participating for 36%, EXXI for 9%, and W.A. “Tex” Moncrief for 5%.  Why? Because MMR now knows more about the SWUD than any other company.  For sure, the view is that perhaps geologically this play extends onshore and not just in the shallow water. This well will explore that concept and is located halfway between (on an east/west axis) Davy Jones and Chevron’s Bear Hump well which has been completed and is now being evaluated. What MMR has mastered over these last few years at Blackbeard West, Blackbeard East, Lafitte, and its Davy Jones’ discoveries is now critical for anyone who is also pursuing bounty in the general area and at the depths below 20,000 feet that have become the new  exploration frontier.

During February, Bobby Ryan, Chevron’s VP of Global Exploration, spoke at another oil and gas conference about their enthusiasm for the SWUD and the work they are doing with MMR.  On page 15 of its presentation, it describes the UltraDeep Gas Play as new play in a mature basin.  Chevron can easily be a player because it already controls major acreage from wells drilled long, long ago and that are still producing to retain the leases. On that same slide, Davy Jones is listed as an exploration discovery. Who knew CVX was a player in DJ?

The transcript contains the following information:

“All eyes are focused on Davy Jones, that McMoRan-operated well, which we’re into a royalty position, is preparing for a test soon, 25,000 pound test equipment. This is a significant environment in the sense of geologically from what we’re typically used to. So we’ll be watching the results of that well. Meanwhile, we’re drilling and just spudded on December 31st, the Lineham Creek well you see onshore Louisiana there. In fact, Bear’s Hump was actually onshore as well.”

If you have ever wondered why the DJ participation percentages never quite added up to 100%, now we know.  Chevron does not have a working interest but it does have a royalty interest in DJ.  In probing, we also learn that somehow in the negotiations that have gone on this year between CVX and MMR, Chevron has also obtained access to the DJ logs and geological evaluations and interpretations which would not normally be available to a royalty interest holder.

Moffett has told us in no uncertain terms that he intends to bring in a partner with very deep pockets to help develop the Ultra Deep play.  He has also told us he plans to follow the model he used for the development of the Grasberg Mine at Freeport Copper and Gold (FCX) years ago.  In that case, Rio Tinto came along for the ride after paying FCX $1.5 billion for which it received ZERO participation in anything that had already been discovered up to that point.  It then paid up for a half participation of what came after.  Perhaps we are in the very early stages in the mating dance between MMR and Chevron.  Don’t expect a rush on that. For sure, Jim Bob won’t do anything until he has proved up exactly what he has so the reserve engineers are happy and he is fully paid for all the hard pioneering work of the last several years.

We know that for a long time, the SWUD detractors have said there is nothing to be found in the Ultra Deep. So much has now been found that viewpoint has become ridiculous. Of course, flowing these wells is still to come.  Another key in the shallow water is that offshore LA there are existing pipelines to carry these new discoveries to market right away. Billions will not have to be spent over future years to accomplish that part of the equation from the deepwater discoveries.   As our country shifts, ever so slowly,  away from coal and nuclear power and toward Natural Gas, nearby infrastructure is a very good thing.

The detractors have also said repeatedly, if this is such a great play, then why aren’t any majors involved?  Well, clearly now there are!  They aren’t just talking about it in whispers any longer.  Chevron is starting to SHOUT about it. It’s about time.   Or as Jim Bob said on a conference call last year: “Hallelujah, Hallelujah!”

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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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Gulf of Mexico True Believers on Pins and Needles as McMoRan completes Davy Jones

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Davy Jones Production Platform

Joan Lappin, Contributor

A lot is happening in the Shallow Water Ultra Deep drilling program that McMoran and its astute partners, Energy XXI and Tex Moncrief, have been pursuing for the last few years.  Now that the U.S. space shuttle program has come to an end, the scientific frontier in this country has moved to drilling miles into the earth’s crust instead of launching men to the moon. Those over 50 are old enough to remember the tension everyone in America felt as the first U.S. spacemen disappeared around the back of the moon and were temporarily out of communication with the Mission Control Center in Houston. Nobody knew if they would continue past the moon and out into space or circle back around into view as planned.

These days the exploration frontier is 30-35,000 feet below the mudline in the Gulf of Mexico.  Petroleum engineers are designing tools and rigs to control the 400 degree temperatures and 20,000 and more lbs. of pressure being encountered by drill bits and logging tools working 6 miles into the earth.

On September 2, 2009, BP announced a massive oil discovery at its Tiber well in what was then one of the deepest wells yet drilled to a total vertical depth of 35,055’ in 4132 feet of water in the Wilcox and Tuscaloosa formations 250 miles Southeast of Houston.  The discovery was described as having multiple pay zones in the “lower tertiary.”  Kaskida, another BP well was announced as having 800’ of hydrocarbon bearing sands about 45 miles SE of Tiber.  Neither of these wells is in production and it is likely to be many years and many billions of dollars spent to build pipelines and solve lifting problems before they are.

In contrast, the Davy Jones 1 well was announced as a discovery by McMoRan and its partners in January 2010, just a few months after the Tiber discovery.  It is about to come online and into production almost any day now.  What’s the difference?  DJ1 is in 20 feet of water just off the coast of Louisiana. Drilling for oil and gas in the Louisiana almost swamp land has been going on for decades.  There are existing pipelines all over the place.  The production platform pictured above is in water that a tall NBA player could almost stand in and wave his arms above the surface.

So everyone is waiting with great anticipation just as for those astronauts circling the moon for the first time decades ago.  McMoRan, the operator, had long ago announced expected completion of the well in mid-December 2011 with perforation of the well casing and a flow test to follow shortly thereafter before the end of the year.

Davy Jones and the Ultra Deep wells don’t give up their booty without a fight.  This is no exception.  It is not certain how fast the reaming of the well will proceed. Might be before year end and it might not.  For sure, the goal is to move at the “proper” speed to successfully complete and test the well. No other course would make sense when the well has cost about $170 million so far. Other than satisfying Wall Street, whether the well is completed on December 20th or January 10th is irrelevant. In this case, slow and secure is the way to go.

The real issue since this play began is that for years many of the other oil and gas exploration companies have disparaged the whole idea that anything worth pursuing would ever be found.  Once it was, the next group of naysayers were convinced that like BP’s Tiber and Kaskida, it would be impossible to produce them.  Earlier this year, in an astounding tip of the hat to a small E&P company like MMR, Chevron complimented MMR’s Jim Bob Moffett and elevated the Gulf of Mexico to its top three exploration zones.  Oil folks in the know are no longer putting down this concept that under the exhausted shallow fields in the Gulf and under the salt weld, more hydrocarbons would or could be found.  Now it is accepted that massive amounts might still be found altering our nation’s energy future.

The expectation for Davy Jones 1 is that once the inside of the hole is smoothed (reamed)  new production liner will be placed into the hole. Next the well casing will be perforated to allow production to begin.  Gas and hopefully some liquids too, will come surging up the well. There is a range of estimates but some folks believe that as the well is perforated from the bottom up, the initially activated zones will begin producing 20 MMcf per day building to the 50-70 MMcf per day level MMR expects to produce.  Because this well is in a hole originally designed years ago to go to only a 20,000’ depth, its small size limits production to a maximum of 75 MMcf per day. Those constraints will not apply to Davy Jones 2, drilled 2.5 miles away which was designed from the outset with much larger pipe and to go to a 30,000’ depth. The second  well is due on stream in the second half of 2012, even less time than the two years it has taken to design the equipment needed to bring Davy 1 onstream.

In the world of exploration and production nothing is ever certain. However, MMR expects to have some additional good news to report before year end at either its Lafitte well or at Black Beard East. In all cases, Moffett is looking at both of these wells for the same Wilcox and Tuscaloosa sands such as the Frio which has previously been seen at Blackbeard East and which is a massive producer onshore Louisiana .  This zones have also been seen offshore at BP’s Tiber and Kaskida wells.  Good things are just around the bend but until then, nervous anticipation is the mood of the week.

Joan E. Lappin CFA              Gramercy Capital Mgt. Corp.

In these turbulent times, put our decades of experience to work for your portfolio.  Contact us at info@gramercycapital.com

Gramercy Capital, its clients and Mrs. Lappin own shares in McMoRan and Energy XXI.  They do not own shares in BP or Chevron, also mentioned in this article.

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