Worldwide Field Development News Jul 6 – Jul 12, 2013

This week the SubseaIQ team added 5 new projects and updated 23 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.

Asia – SouthEast

Premier Close to Commissioning Anoa Phase 4

Jul 12, 2013 – Premiere Oil announced that on June 21 a planned 4-week shutdown of the Anoa field gas processing facility commenced to allow the completion of the Phase 4 compression project. The project was implemented to add additional gas processing capacity to handle the decline of oil production and the increase of associated gas production. First gas is expected near the end of July with final commissioning to be complete by September. Phase 4 will allow the commercialization of roughly 200 Bcf of undeveloped proven reserves. The Anoa field is located off Indonesia in Natuna Sea Block A. Premier (28.667%) operates the field on behalf of its partners KUFPEC (33.33%), Hess (23%) and Petronas (15%).

Project Details: Anoa

KrisEnergy Hits Gas Pay with Tayum-1

Jul 12, 2013 – KrisEnergy, operator of the Kutai PSC offshore Indonesia, announced the completion of drilling operations at the Tayum-1 exploration well. Shelf Drilling’s Randolph Yost (300′ ILC) drilled the well directionally to a measured depth of 11,095 feet (8,410 feet total vertical depth). Almost 50 feet of net gas pay was encountered over multiple sandstone intervals. The well has been plugged and abandoned as a gas discovery.

Project Details: Tayum

Nido Petroleum Secures SC54A Extension

Jul 11, 2013 – Nido Petorleum secured a 12-month extension from the Philippines Department of Energy relating to Sub-Phase 6 for Service Contract (SC) 54A. Sub-Phase 6 now has an effective end date of Aug 4, 2014 and Sub-Phase 7 will commence Aug 5, 2014 and last for 12 months. The extension allows Nido and its partners additional time to complete engineering and development studies prior to making the decision on whether or not to enter Sub-Phase 7. Lawaan is the leading drillable prospect in SC54A with oil-in-place estimates of 34.7 million barrels.

Project Details: Lawaan

Africa – West

Starfish Comes up Dry off Ghana

Jul 11, 2013 – Ophir Energy’s Starfish-1 well has been drilled to 14,370-feet total depth (TD) by the Stena DrillMax (UDW drillship) in the Accra PSC offshore Ghana. A wireline logging program was carried out in the well that confirmed over 750 feet of gross water-bearing sandstone in the primary target. The secondary target was determined to be comprised of poorly developed sands that were also water-bearing. Evaluation of the logging data will continue in an effort to help the PSC partners decide by the Sept. 23-deadline on whether or not to proceed with the Phase 2 work program.

Project Details: Starfish

Pieces Falling in Place for Welwitschia Probe

Jul 11, 2013 – The partners in Namibian license PEL0010 selected the new-build Rowan Renaissance (UDW drillship) to drill the Welwitschia-1 exploration well. Rig delivery is expected to take place in December 2013, at which point the drillship will sail directly to Namibia to spud the well in mid-February 2014. Detailed well planning is underway and a site has been selected that will allow the well to test the primary and secondary targets in Maastrichtian and Aptian-Albian reservoirs. Procurement of long-lead items is underway with deliveries to begin by the end of the year. License partners include Repsol (44%) as operator, Tower Resources (30%) and Arcadia (26%).

Project Details: Welwitschia

Europe – North Sea

Blackford Dolphin Locked to Drill Aragon

Jul 12, 2013 – Bridge Energy, a partner in UK license P1763, announced the Blackford Dolphin (DW semisub) has been contracted by operator-MPX North Sea to test the Aragon prospect with an estimated spud date in 1Q 2014. Aragon is located near the Beryl field and the well will be target sands in the Upper Jurassic Heather formation. Drilling the exploration well will fulfill a work commitment that needs to be completed before 1Q 2015.

Project Details: Aragon

Premier and KUFPEC Increase Bream Interests

Jul 12, 2013 – Premier Oil and KUFPEC Norway AS have entered into an agreement to acquire BG Group’s entire 40% interest in license PL407 on the Norwegian continental shelf. If approved by regulatory authorities, the revised license ownership will consist of Premier (50%) as operator, KUFPEC (30%) and Tullow (20%). PL407 contains the Bream discovery which has been estimated to contain around 50 MMboe. Development of the field is expected to be sanctioned at some point in 2014.

Project Details: Bream

Lundin Adds to Johan Sverdrup Reserves

Jul 12, 2013 – Lundin Petroleum announced the successful completion of its latest Johan Sverdrup appraisal well. Well 16/3-6 was drilled by the Bredford Dolphin (mid-water semisub) to a depth of 6,643. A 37-foot oil column was discovered in good quality Upper Jurassic sandstone. The rig will now mobilize to license PL544 to drill well 16/4-7 on Lundin’s Biotitt prospect.

Project Details: Johan Sverdrup

Cairn Farm-In Approved by Ireland’s DCENR

Jul 12, 2013 – Cairn Energy’s 38% farm-in as operator of Frontier Exploration Licenses (FEL 2/04) and 4/08 has been approved by Ireland’s Minister of State at the Department of Communications, Energy and Natural Resources (DCENR). License FEL 2/04 contains the Burren and Spanish Point discoveries and FEL 4/08 holds the Cama oil prospect. Cairn has contracted the Blackford Dolphin (DW semisub) to drill an appraisal well at Spanish Point in 2Q 2014. In addition to the two FELs, Cairn also secured operatorship of a licensing option in the Porcupine Basin covering 1,062 square miles.

Project Details: Spanish Point

NPD Issues Drilling Permit for Iskrystall Wildcat

Jul 11, 2013 – The Norwegian Petroleum Directorate (NPD) granted Statoil a permit to drill an exploration well at its Iskrystall prospect in license PL608. Well 7219/8-2 will be drilled by the West Hercules (UDW semisub) in 1,128 feet of water. The well will test a similar early-middle Jurassic play that was proven by the Skrugard and Havis discoveries but is thought to lie at a much greater depth at Iskrystall.

Project Details: Iskrystall

Ocean Vanguard Spuds Cliffhanger North

Jul 11, 2013 – Lundin Petroleum announced the spud of well 16/2-18S in Norwegian license PL265. The well is being drilled by the Ocean Vanguard (mid-water semisub) to test the presence of quality Jurassic reservoir and the quality of fractured and weathered basement rock. Additionally, the well will serve to delineate the northeast extension of the Johan Sverdrup discovery. The rig is expected to be on location for 40 days while drilling to the proposed total depth of 6,463 feet.

Project Details: Johan Sverdrup

Australia

Gas Discovery Confirmed at Bianchi-1

Jul 11, 2013 – A wireline logging program being carried out in Apache’s Bianchi-1 well off Western Australia was interrupted to conduct unspecified repairs to the Ocean America (DW semisub). Enough data was acquired prior to the shut-down, confirming a gas discovery in the upper sands of an interval that LWD data indicated to be gas-bearing. The Bianchi joint venture has agreed to drill an additional 100 feet to a total depth (TD) of 17,789 feet. Upon reaching TD, the wireline program will recommence to complete the evaluation of the well.

Project Details: Bianchi

Pryderi Partners Granted Permit Extension

Jul 11, 2013 – IPB Petroleum and CalEnergy were granted a 12-month suspension and extension to years 2 and 3 regarding the work program for permit WA-424-P off Western Australia. A tight rig market prompted the joint venture partners to seek the extension in order to have more time to source a suitable rig to drill an exploration well on the Pryderi prospect. The extra time also allows for the submission of needed revisions to the Pryderi Environmental Plan and Oil Spill Contingency Plan. Submission of the revisions is expected to take place mid-July 2013. Assuming the revisions are accepted and all regulatory approvals are granted, IPB expects to be ready to spud Pyderi-1 in 4Q 2013.

Project Details: Pryderi

Canada: Spectra Energy, BG Sign Project Development Deal

Spectra Energy Corp announced that the company has signed a Project Development Agreement with BG Group to jointly develop plans for a new natural gas transportation system from northeast B.C. to serve BG Group’s potential liquefied natural gas (LNG) export facility in Prince Rupert, on the province’s northwest coast. Spectra Energy and BG Group will each initially own a 50 percent interest in the proposed transportation project.

Spectra Energy will be responsible for construction and operation and BG Group has agreed to contract for all of the proposed capacity.

The approximately 850-kilometre (525 mile), large diameter natural gas transportation system will begin in northeast B.C. and end at BG Group’s potential LNG export facility in Prince Rupert. The new transportation system will be capable of transporting up to 4.2 billion cubic feet per day of natural gas. The project also will connect with the Spectra Energy system at Station 2 (southwest of Fort St. John), a growing natural gas hub that collects supply from multiple areas of the province and other supply basins in Western Canada.

“We are excited to be partnering with BG Group, a recognized world leader in natural gas and more specifically, LNG,” said Greg Ebel, president and chief executive officer, Spectra Energy. “This project offers B.C. a unique opportunity to access new markets, strengthen its energy infrastructure, engage stakeholders in economic growth and job creation, and ultimately secure the province’s position as a competitive energy leader.”

“Furthermore, today’s announcement initiates our next wave of investment opportunity in B.C. We are ideally positioned to create further value for our investors by leveraging surplus B.C. natural gas supplies and facilitating its export to high-demand markets in Asia. This, in turn, will provide multiple opportunities for further investment in our gathering and processing facilities in the province,” added Ebel.

“For more than half a century, Spectra Energy has been a part of communities in B.C.,” said Doug Bloom, president, Spectra Energy Transmission West. “This project will build on our expertise and track record of delivering natural gas responsibly, listening to the needs of Aboriginal and local communities, and protecting the environment, as we help deliver on B.C.’s energy potential.”

Working together with affected stakeholders and based on preliminary assessments of environmental, historical, cultural and constructability factors, early conceptual routes have been developed. Spectra Energy and BG Group will continue engaging with interested and affected stakeholders, including Aboriginal and local communities, environmental organizations and regulatory agencies, to further refine the project route.

In addition, the companies will spend the next several years closely conferring with stakeholders and working through the permitting process for the proposed transportation system. This work will include filing a project application with the B.C. Environmental Assessment Office. Based on the results of these efforts, project construction is currently expected to commence mid-decade, with service starting by the end of the decade.

As part of this commitment to transparently communicate and foster relationships in the province, Spectra Energy also announced “Energy for BC”. The new outreach initiative is designed to engage with stakeholders on the jobs, revenues and environmental benefits that natural gas can create in British Columbia.

Spectra Energy, BG Sign Project Development Deal, Canada LNG World News.

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Recap: Worldwide Field Development News Jul 20 – Jul 26, 2012

This week the SubseaIQ team added 2 new projects and updated 29 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 – West

Rialto Spuds Gazelle-P4 Development Well

Jul 26, 2012 – Rialto Energy spud the Gazelle-P4 development well using the GSF Monitor (350′ ILC) jackup. Gazelle-P4 is testing the oil potential of the UC-2 and UC-4 oil reservoirs as well as the gas potential of the UC-3, UC-5, LC-1 and LC-2 gas reservoirs discovered by the IVCO-12 and IVCO-21 wells. The Gazelle-P4 well is expected to take approximately 45 days.

Project Details: Gazelle

N. America – US GOM

Murphy to Appraise Diamond in GOM

Jul 25, 2012 – Murphy announced plans to appraise its Diamond discovery at Lloyd Ridge Block 370 in the Gulf of Mexico. Diamond is estimated to contain between 400 billion and 500 billion cubic feet of gas, according to Murphy Chief Executive Claiborne Deming. Depending on the results, Murphy will either keep the rig on site for appraisal drilling or move it to a third prospect, Emerald. Located in Lloyd Ridge Block 317, the Emerald prospect potentially has 150 Bcf of gas in recoverable reserves.

Project Details: Diamond

Newfield Mulling Winter Development Options

Jul 25, 2012 – Deep Gulf Energy reported that the Winter discovery, which was drilled in June 2009, is temporarily abandoned as various development options are under consideration. The discovery is in close proximity to the DGE operated GB 339 Sargent well that is tied-back to the GB 72 fixed platform.

Project Details: Winter

N. America – Canadian Atlantic

Husky Energy to Finalize White Rose Extension Project

Jul 24, 2012 – In May 2012, Husky filed a project description with regulators for the White Rose Extension project. The company expects to make a decision on a preferred development option later in 2012, which will use existing infrastructure at the White Rose field and the existing SeaRose FPSO facilities for processing and storage.

Project Details: White Rose

Sea Rose FPSO to Resume Production in 3Q12

Jul 24, 2012 – The Sea Rose FPSO has been reconnected, reported Husky Energy. Following planned off-station, production is expected to resume in 3Q 2012. An infill production well was drilled at the White Rose field and will be brought online once production resumes. Furthermore, development drilling continued at North Amethyst and a supporting water injection well for the West White Rose pilot project was completed.

Project Details: White Rose

S. America – Brazil

Fluke Engenharia to Fabricate 27 Suction Piles

Jul 25, 2012 – Fluke Engenharia has received a contract from Subsea 7 to fabricate 27 suction piles for use in the Guara-Lula field, which is part of the pre-salt cluster in the Santos basin offshore Brazil. Fluke Engenharia will manufacture the products at its Macae facilities and will deliver them over the course of 2012.

Project Details: Sapinhoa (Guara)

BG Group Signs Contracts for Topside Modules for Lula, Sapinhoa FPSOs

Jul 20, 2012 – BG Group and partners have approved the signature of contracts totaling $4.5 billion for the construction of the first six topside modules and integration packages for eight domestic floating production, storage and offloading units to be used on the Lula (Tupi) and Sapinhoa (Guara) pre-salt projects offshore Brazil.

Project Details: Lula (Tupi)

Asia – Far East

Husky Energy Progresses Liwan Gas Project

Jul 24, 2012 – Husky Energy reported that the Liwan gas project in the South China Sea is advancing as planned with the completion of the shallow water jacket for the project, and the topsides portion of the platform scheduled for completion in the second quarter of 2013. The installation of all nine subsea production trees was completed on the wells at the Liwan 3-1 gas field. Six associated upper completions were installed and flow-tested, with production rates as expected. Front-end engineering and design work for the development of the Liuhua 29-1 gas field is underway. Negotiations are continuing on a sales agreement for gas from the Liuhua 34-2 field. The development is on target to realize first production in late 2013/early 2014.

Project Details: Liwan

Asia – SouthEast

Development Drilling Commences at Madura Project

Jul 24, 2012 – Husky Energy stated that drilling has commenced at a planned six-plus well exploration program in the Madura Strait Block offshore Indonesia. A joint development plan for the MDA and MBH fields has been submitted to the government. The award of development contracts for the BD Field, including a leased FPSO, is expected later this year. The Company and its partners are moving to fully delineate and develop the Madura Strait Block with first gas anticipated in 2014.

Cairn India to Explore Sri Lanka Block in 2013

Jul 23, 2012 – Cairn India Limited reported that the potential commercial interest notification has been submitted for two discoveries, the Dorado and Barracuda wells, as per the terms of the Petroleum Resource Agreement. The operator plans to conduct an exploration program in mid-2013, and tendering for the drilling rig and the associated services is in progress.

Project Details: Dorado

Manora Oil Development to Precede

Jul 23, 2012 – The Manora oil development is scheduled to proceed after its joint venture partners reached a final investment decision. The $246 million project will see a single wellhead platform linked to a floating, storage and offtake unit and the drilling of 15 development wells consisting of 10 production and five injection wells. Tap said that several prospects are being finalized based on recently acquired 3D seismic. The project has also secured a rig to dill up to three wells later this year, and drilling is scheduled to start in the second half of this year. First oil from Manora is being targeted for early 2014 with output expected to peak at about 15,000 barrels per day. The Manora oil development consist of two offshore concessions – G1/48 and G3/48 – sited in the northern Gulf of Thailand. The two concessions could contain up to 31 million barrels of recoverable oil resources.

Project Details: Manora

Mediterranean

Noble Energy Completes Flow Test at Pinnacles

Jul 20, 2012 – Noble Energy Mediterranean has reported that the flow tests of Pinnacles-1 have been completed. Gas composition and gas treatment measures were tested and proved to be effective. The operator will now begin the natural gas flow from the reservoir.

Europe – North Sea

Barryroe is a Huge Find for Providence

Jul 25, 2012 – Providence Resources confirms that estimates of the size of its Barryroe find in the Celtic Sea offshore Ireland have been upgraded. The company reported that its oil in place estimates for Barryroe were now 1,043 million barrels of oil on a P50 basis and up to 1,612 million barrels on a P10 basis. On July 6, oil analysts at Liberum Capital speculated that Barryroe could contain around one billion barrels of oil in place and more than 160 million barrels of recoverable oil. After Providence’s announcement, the London-based investment bank upgraded its estimate of recoverable reserves to 200 million barrels. Providence said that after the successful drilling and testing of the Barryroe 48/24-10z well in March, it has now completed a series of comprehensive post-well studies in order to update the in-place volumetric resource estimate for the Barryroe discovery.

Project Details: Barryroe

Centrica Cooper Well Finds Hydrocarbons

Jul 25, 2012 – Faroe Petroleum reported that its Cooper well in the Norwegian sector of the North Sea has encountered hydrocarbons. The well made a discovery in the Middle Jurassic Garn formation at a depth of 17,500 feet (5,334 meters). After analyzing preliminary results Faroe, and its partners in the well, are now performing a drill stem test (DST) of the Garn formation to evaluate the likely productivity of the reservoir. The Cooper well (in which Faroe has a 30-percent interest) was drilled using the West Alpha (mid-water semisub) rig. It is located in license PL477 on Block 6506/11 on the Halten Terrace.

Project Details: Cooper

Lundin Further Appraises Johan Sverdrup

Jul 25, 2012 – Lundin spud its fifth appraisal well on the Johan Sverdrup discovery in the Norwegian sector of the North Sea. The 16/2-13 well is situated about 1.5 miles (2.4 kilometers) northeast of the discovery well that was found in 2010. The main objective is to determine the top reservoir, reservoir quality and thickness, as well as oil-water contact in this part of the field. The planned total depth of the well is 7,050 feet (2,148 meters) and drilling operations are being conducted by the Transocean Arctic (mid-water semisub). Drilling should take about 45 days.

Project Details: Johan Sverdrup

Statoil Gets Govt Nod to Drill on Valemon

Jul 25, 2012 – Statoil has received consent from the Petroleum Safety Authority Norway to use West Elara (490′ ILC) jackup at the Valemon field. The consent relates to the hook-up of West Elara to the jacket, drilling and installation of 30-inch conductors in the planned first 12 wells and drilling well B-20 for injection of drill cuttings and mud in the Utsira formation. The planned start-up date is July 15, 2012.

Project Details: Valemon

Expro to Provide Well Testing and Data Management Services at Bentley Field

Jul 23, 2012 – Expro has received a contract to provide equipment and services in support of Xcite Energy’s 90-day extended well test in the Bentley field. Expro will provide heavy oil well testing and data management services through drilling and completions company ADTI on the Rowan Norway (400′ ILC) jackup. The Bentley field is estimated to contain 116 million barrels of proven and probable reserves.

Project Details: Bentley

Lundin to Appraise Well in PL 490

Jul 23, 2012 – Lundin has received consent to conduct appraisal drilling on Production License 490. A possible sidetrack (7120/6-3 A) may also be drilled. The Transocean Arctic (mid-water semisub) will conduct drilling operations in a water depth of 1,073 feet (327 meters). Drilling activities are estimated to last a total of 133 days, including the possible sidetrack well.

Project Details: Skalle

Talisman Gets OK to Drill on Varg

Jul 23, 2012 – Talisman Energy has received consent to use Rowan Stavanger (400′ ILC) jackup to drill three sidetrack wells on the Varg field. The consent relates to the drilling of three sidetracks in wells 15/12-A-3 B, 15/12-A-12 E and 15/12-A-1 B on the Varg field. Water depth of the site is 285 feet (87 meters) and drilling should take 62 days.

Project Details: Varg

Petrofac Wins Extended North Sea Contract

Jul 20, 2012 – Petrofac has been awarded a three-year contract to supply engineering and construction services to Apache North Sea. Petrofac will supply onshore engineering as well as onshore and offshore construction to all of Apache North Sea’s assets, including the Beryl Alpha and Bravo platforms in the northern North Sea. The contract represents an extension to, and continuation of, the firm’s current service contract to service Apache’s offshore platforms in the Forties field, 110 miles (177 kilometers) east of Aberdeen.

Providence Approves 2012 Budget for Spanish Point Discovery

Jul 20, 2012 – Providence Resources and partners have approved the 2012 budget for the Spanish Point discovery, as the companies prepare for the 2013 drilling campaign. The gas condensate discovery is located in a water depth of 1,300 feet (396 meters) in the Main Porcupine Basin 125 miles (201 kilometers) off the west coast of Ireland. The 2012 budget includes the provision for well design activities as part of the ramp up to a 2013 appraisal drilling program on Spanish Point. The plan is to spud the initial appraisal well in the third quarter of 2013 subject to rig availability and government approvals while the partners have agreed to transfer the operatorship of FEL 2/04, along with that of other licenses from Providence to Chrysaor.

Project Details: Spanish Point

Australia

Alcatel-Lucent, Technip to Provide Advanced Communications System

Jul 26, 2012 – Alcatel-Lucent together with the Technip Samsung Consortium (TSC) is set to provide an advanced communications system for Shell???s new Prelude FLNG facility. The system will enhance the safety and efficiency of operations and provide entertainment and communications services for crew members on the facility, 124 miles (200 kilometers) off Western Australia. The communications system will include operations, safety, and entertainment systems such as: trunk and marine radio communications; air communications radar recorder (black box); beacons; local and wide area networks; voice over IP; closed circuit TV; public address alarm systems; distress and safety systems; GPS; weather monitoring; and search and rescue transponders.

Project Details: Prelude

Chevron Finds Additional Gas in Gorgon Area

Jul 23, 2012 – Chevron has made a natural gas discovery in the Greater Gorgon area of the Carnarvon Basin, offshore Western Australia. The Pontus-1 exploration well encountered approximately 97 feet (30 meters) of net gas pay. The well is located in the WA-37-L permit area in the Greater Gorgon Area gas fields, approximately 40 miles (65 kilometers) northwest of Barrow Island. The well was drilled in 690 feet (210 meters) of water to a total depth of 16,581 feet (5,054 meters). Chevron Australia is the operator of WA-37-L and holds a 47.3% interest in the permit. Exxon Mobil and Shell Development Australia both hold 25%, Osaka Gas holds 1.25%, Tokyo Gas holds 1% and Chubu Electric Power holds approximately 0.42%.

Project Details: Greater Gorgon

GE Oil & Gas Receives Gorgon Contract

Jul 23, 2012 – GE Oil and Gas has been awarded a $600 million service contract to maintain the compressor trains and associated equipment at Chevron’s Gorgon LNG project off the northwestern coast of Australia. Under the 22-year agreement, GE will provide Chevron with scheduled maintenance, monitoring and diagnostics of the installed equipment and access to local engineers. GE will also manage inventory and supply initial spare components. GE’s first contract performance manager will start working in Perth in October 2012.

Project Details: Greater Gorgon

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5th Discovery in a Row for BG Group Offshore Tanzania

BG Group today announced its fifth consecutive Tanzania gas discovery with the Mzia-1 exploration well located in Block 1, offshore southern Tanzania.

Mzia-1 is BG Group’s first discovery within the deeper Cretaceous section and opens an extensive new play fairway within the Group’s offshore acreage in Blocks 1, 3 and 4, to complement the now proven Tertiary fairway.

Preliminary evaluation of the results indicates 55 metres of natural gas pay in good quality sands. An extensive logging programme has been completed, including the acquisition of pressure data and gas samples.

Significantly, the well has de-risked a number of adjacent Cretaceous prospects, which could form part of a future Mzia hub. These prospects are expected to be tested in a future appraisal programme to be defined following incorporation of data from this new well and 3D seismic.

The new resources proven by Mzia and the potential of adjacent prospects are currently under evaluation. Prior to drilling Mzia-1, BG Group had estimated mean total gross recoverable resources approaching 7 trillion cubic feet of gas from the four previous discoveries drilled in Tanzania.

Mzia-1 is approximately 45 kilometres offshore southern Tanzania in a water depth of 1 639 metres. It is some 23 kilometres from the Jodari-1 discovery and is part of the 2012 three-to-four well exploration programme.

Following the imminent completion of operations at Mzia, the Deepsea Metro-1 will relocate to Block 3 for the drilling of the next exploration prospect, Papa-1.

BG Group as operator has a 60% interest in Blocks 1, 3 and 4 offshore Tanzania, with Ophir Energy plc holding 40%.

Source

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Apache Hires Drillship for Ops Offshore Kenya

Pancontinental Oil & Gas NL reports that the Kenya L8 licence operator Apache Kenya Limited (Apache) has secured the use of the deepwater drilling ship Deepsea Metro 1 to drill the giant Mbawa Prospect.

Apache is anticipating a spud date within Q3 2012, with the actual date depending on when the drilling rig is finished with its current operations.

The well is expected to take some 45 to 60 days to complete to a planned total depth of 3,250m subsea in water depth of 860m, easily within the range of modern equipment.

Pancontinental has a 15% interest “free-carried” through Mbawa drilling by Tullow Oil plc up to a “cap” of US$ 9 million (as may be reduced by other exploration expenditure). Pancontinental now expects to have contribute more to the well cost due to increased well cost estimates.

Pancontinental estimates that Mbawa has maximum potential to contain 4.9 Billion Barrels of oil in place at the main Tertiary / Cretaceous level with significant additional potential also to be tested by the well at the deeper Upper Jurassic level and shallower Tertiary levels. Only drilling is capable of verifying the oil and gas volumetric potential (if any) of the Mbawa Prospect.

Pancontinental has four projects offshore Kenya covering more than 18,000 square kilometres in licence areas L6, L8, L10A and L10B, with the L8 / Mbawa project being the most advanced and Mbawa being the first prospect to be drilled.

Pancontinental’s CEO Barry Rushworth commented;

“Pancontinental is in the unique position of having sizeable interests in a number of Kenyan and Namibian offshore licences and having substantial leverage to any Mbawa drilling success.  We are very pleased that a drilling rig contract has now been signed by our operator Apache for the L8 Mbawa Prospect. We are pursuing what we see as a major oil play rather than a gas play offshore Kenya and we are doing the same offshore Namibia.  The economics of oil developments are often far better than those for gas, with potential for much earlier cash flow and much lower development costs compared to LNG, for example. Apache is now leading the L8 venture in an aggressive exploration programme and in our other Kenyan blocks L10A and L10B we also have fast-moving activity led by BG Group”.

Source

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Will the US Become the World’s Largest Exporter of LNG?

Sabine Pass Liquefied Natural Gas (LNG) Terminal, Cameron Parish, Louisiana. LNG ship, Celestine River, moored at the unloading berth of Cheniere Energy's $800M terminal following her maiden voyage with the project's first cargo. Image: Bechtel

 

By John R. Siegel

(Barrons) By 2017 the U.S. could be the largest exporter of liquefied natural gas in the world, surpassing leading LNG exporters Qatar and Australia. There is one big “if,” however. America can produce more gas, export a surplus, improve the trade deficit, create jobs, generate taxable profits and reduce its dependence on foreign energy if the marketplace is allowed to work and politics doesn’t get in the way.

In May 2011 Cheniere Energy received an Energy Department license to export LNG from its Sabine Pass LNG import terminal in Louisiana. Cheniere subsequently reached long-term deals with the U.K.’s BG Group, Spain’s Gas Natural and India’s GAIL. Cheniere is targeting operation in 2016 and plans to export up to 730 billion cubic feet of LNG annually, roughly 3% of current U.S. gas production.

Sabine Pass originally was built as an import facility to alleviate projected U.S. gas shortages. Shale-gas technology changed that assumption radically. Now Sabine Pass is attractive because it already possesses much of the infrastructure for an export plant: LNG storage tanks, gas-handling facilities and docking terminals. Only a liquefaction plant is needed to convert natural gas into LNG. Overall, Cheniere can create its export terminal for half the investment required for a new one.

With world oil over $100 per barrel, equivalent to $17 per million BTUs of gas, versus domestic natural gas at $2.10 per million BTUs, the opportunity is obvious: Cheniere can deliver its gas to Asia or European customers well below current market prices.

Six developers with existing import terminals are following the Sabine Pass model. And Cheniere has another project in Corpus Christi. With the expansion of the Panama Canal, Gulf LNG projects can economically target the lucrative Asia market. By 2017, the U.S. could be exporting upwards of 13 billion cubic feet of LNG per day.

But exporters must overcome growing opposition to LNG exports by environmentalists and industrial users of natural gas. Exporters must also get multiple permits from environmentally conscious federal officials. And Rep. Ed Markey (D.-Mass.) has proposed legislation to bar federal approval of any LNG export terminals until 2025. Those who most fear global warming don’t want anyone anywhere to use more fossil fuel, even “cleaner” natural gas.

It is uphill for the anti-gas crowd. High oil prices are driving a transition to natural gas, even as fuel for trucks and cars. In the U.S., the T. Boone Pickens Plan would displace gasoline and diesel fuel for compressed natural gas in large trucks. Pickens estimates savings of two million barrels per day of oil imports if the nation’s fleet of 18-wheelers converts to CNG. The Pickens Plan might fail legislatively because it calls for subsidies to fuel the transition. But if CNG’s nearly $2-per-gallon price advantage over gasoline continues, the concept will evolve via natural market forces, as it should.

THE ENERGY DEPARTMENT SAYS natural gas has grown its market share in the U.S. in the past three years from 28% to 30%. Globally, the trend is similar, and LNG is integral to the global supply chain.

Despite the recession, global LNG demand has been growing at a 6% to 8% annual clip for the past 10 years. When demand collapsed in 2009, prices in Asian markets fell 50% to about $5 per million BTUs. But the price drop was also driven by the rapid growth in U.S. shale gas. U.S. natural-gas supply — flatlined for a decade at 19 trillion to 20 trillion cubic feet annually — increased 15% in the past three years due to the shale-gas revolution. Technology advances created a supply perturbation. As U.S. gas prices plunged, LNG cargoes bound for the U.S. had no market.

Global LNG markets are growing again. By late 2010, the main Asian consumers — Japan, Korea and Taiwan — were seeking more LNG, while new customers such as Thailand were entering the market. The Japan tsunami put a call on LNG imports to supplant Japan’s nuclear shutdowns, and with increasing demand, Asian markets rebounded to the $15-per-million-BTU range. After the tsunami, Germany plans to close its nuclear plants. Most of Germany’s (and all of Europe’s) new supply will be gas-fired. Given the choices, would Europe rather grow its gas supply from Russia, North Africa or the U.S.? The policy implications should be obvious, even to the U.S.

Estimates of the job benefits from U.S. LNG projects depend on a variety of assumptions. Roughly 25,000 direct construction jobs would be created if all the projects are built. Increasing the U.S. natural-gas production base by another 13 billion cubic feet might translate to 450,000 direct and indirect jobs and $16 billion in annual tax revenue for federal and state coffers.

It’s easier to forecast improved trade balances. Exporting 13 BCF per day of LNG could generate about $45 billion annually. Reaching Pickens’ goals could offset another $70 billion annually of oil imports.

Exporting energy, however, rubs a lot of people the wrong way. Pickens wants cheap natural gas for his 18-wheelers and opposes LNG exports. Industrial gas users argue that a vibrant LNG industry would propel domestic gas prices higher. A study by Deloitte said that exporting six 6 BCF per day of LNG would raise wellhead gas prices by 12 cents per million BTU (about 1% on a retail basis). Advocates of “energy independence” argue that exporting LNG would tie U.S. natural gas prices to global markets.

The Energy Department’s Office of Fossil Energy is considering whether exporting LNG is in the public interest. In the meantime — shades of Keystone XL — the department has effectively put a moratorium on new LNG export licenses.

Energy’s decision-making process balances the extent to which exporting LNG drives up prices with the economic benefits of increased production and energy exports. The price assessment comes at a time when U.S. gas fetches the same price in constant dollars as it did in 1975. Producers are now shutting down production and lowering exploration budgets. The shale-gas “job machine” is now in reverse.

Energy’s price study, released in January, found that exporting six BCF per day would increase wellhead prices by 50 to 60 cents per million BTU by 2026. The study has a myriad of assumptions and scenarios, the most fundamental of which is future gas production. In 2007, Energy predicted the U.S. would be importing 12.3 BCF a day of LNG by 2030 due to falling gas production. But primarily because of the shale-technology phenomenon, wellhead prices have tumbled from $6.25 six years ago, even as demand increased by eight BCF per day. That demand figure is larger than the six BCF assumption of the Energy study. The Energy Department is not particularly to blame, as most forecasters got it just as wrong on gas production.

Ideally, the Energy Department should move quickly and recognize free-market principles. And the administration could send a clear policy signal that natural gas is integral to the country’s energy future and that exporting LNG is good economics and consistent with its 2010 State of the Union address to double U.S. exports over five years and create two million new jobs. But Energy is moving slowly, and administration signals on natural gas are mostly lip service. The economic-benefits study should have been done by the end of March. But last week, Energy delayed its release until late summer, and said there is no timeline to review results and develop policy recommendations. Translation: after the election.

While we are fantasizing, the government could stop singling out the job-creating energy industry for higher taxes, emphasize cost/benefit analysis before adding further regulation to energy production, and get out of the business of regulating LNG exports altogether, which smacks of protectionism. To that end, should we also give veto authority to the Agriculture Department over grain exports (to lower corn prices) and the Commerce Department over auto, airplane and smartphone exports?

JOHN R. SIEGEL is the president of J.J. Richardson, a registered investment advisor that manages a hedge fund in Bethesda, Md.

Dow Jones & Company, Inc.

By gCaptain Staff On April 8, 2012

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USA: ETE Units File with FERC for Proposed Lake Charles Liquefaction Project

Energy Transfer Equity (ETE) today announced that its Trunkline LNG Company, Trunkline LNG Export, and Trunkline Gas Company subsidiaries have filed with the Federal Energy Regulatory Commission to build the previously announced natural gas liquefaction project under development in Lake Charles, La.

The Lake Charles liquefaction project is being developed to liquefy domestic supplies of natural gas for export to foreign countries in order to meet the growing world-wide demand for LNG. Exporting LNG to the world market will provide a wide range of economic and employment related benefits for the United States.

Energy Transfer and its subsidiaries continue to work closely with its customer BG Group in the development of the project, ETE said in a statement.

As part of the project, Trunkline Gas Company plans to extend its interstate natural gas pipeline approximately half a mile to provide feed gas to the liquefaction facility. The project is currently planned to export up to 15 million metric tons of LNG per year, which is the equivalent of approximately 2 billion cubic feet per day of natural gas. Pending regulatory approvals, Trunkline LNG Export currently expects to begin project construction in 2014 and is anticipating the project to be in service in the spring of 2018.

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ANCAP Reveals Ronda Uruguay II Winners

Uruguay’s state-owned petroleum company, ANCAP, received 19 offers for offshore oil exploration and production on 8 of the 15 offered blocks. Nine oil companies submitted bids from the eleven oil companies initially qualified for the bidding process.

The eight blocks cover more than 50% of the total offered area and they will be placed for exploration works by the four new players in the Uruguayan offshore: the British companies BP and BG, the French company Total and the Irish company Tullow Oil.

After the assessment of the proposals and the approval by the Uruguayan government ANCAP will sign the contracts with the winning companies on September 2012 as a deadline.

There will be a relevant increasing in quantity and quality of the geological knowledge of the offshore basins, as the work plans represent as a whole: one exploratory well at ultra-deep waters, 33.240 km2 of 3D seismic data, 13.080 km2 de 3D electromagnetic data, 130 samples of sea bed, and 3.000 km of 2D seismic data for the first three years of exploration work.

The ANCAP president Raul Sendic highlighted that “the outcomes of the Round imply relevant investments by the oil companies, and therefore there will be significant advances in knowledge and technology, as well as the development of a new services sector”.

The Industry, Mining and Energy Minister Roberto Kreimerman underlined that “Uruguay has a national energy policy that promotes the development of local resources, and ANCAP is a leader in that process. This successful Round also demonstrates that the Uruguay has technical and human expertise and that the world is recognizing the good image of our country”.

The integration of this new 4 top level oil companies to Petrobras, YPF and GALP means the definitive insertion of Uruguay in the world oil map. The winning companies will assume all the risks and costs generated by the oil operations during the phases of exploration and production. The contract is classified as shared production agreement, and under this format the companies are benefited with part of the available production according to the percentages established by the contract. The term of the contract shall be 30 years, and ANCAP may extend the term up to a maximum of 10 years.

The exploratory period comprises a basic sub-period of 3 years, where the companies will execute the compromised exploratory program. There are two voluntary sub periods that involves the production of one exploratory well each, and the last request to return to Uruguay at least the 30% of the area.

ANCAP will have the option for buying totally or partially oil production of the companies if it is needed for the national oil consumption of Uruguay. ANCAP may be associated for the exploitation of each productive block by a percentage offered by each winning company.

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