This week the SubseaIQ team added 4 new projects and updated 13 projects. You can see all the updates made over any time period via the Project Update History search. The latest offshore field development news and activities are listed below for your convenience.
Africa – West
Oct 24, 2013 – Lukoil completed drilling the Savannah-1X wildcat in the Sl-5-11 license offshore Sierra Leone. The well was drilled on schedule by the Eirik Raude (UDW semisub) to a depth of 14,519 feet. Several oil-bearing reservoirs were confirmed and oil samples were taken from Turonian sands. Drilling data will be evaluated through the end of the year to advance the company’s geological understanding of the area.
Project Details: Savannah
Asia – Far East
CNOOC Announces Additional Bohai Bay Discoveries
Oct 24, 2013 – CNOOC announced an oil discovery at its Luda 5-2 North field in Bohai Bay. The Luda 5-2N-2 and Luda 5-2N-4 wells were each drilled to a depth of 3,740 feet and encountered gross pay zones of 390 and 280 feet respectively. Luda 5-2N-2 tested oil at a rate 1,040 barrels per day. Additionally, the company announced the successful appraisal of the Kenli 9-5/9-6 oil field. The Kenli 9-5-2D and 9-6-2 wells were drilled in the southern part of Bohai Bay. Kenli 9-6-2 flowed at a rate of 200 barrels per day.
S. America – Brazil
Petrobras-led Consortium to Develop Pre-Salt Libra Field
Oct 24, 2013 – A group of companies comprised of Petrobras, Shell, Total, CNPC and CNOOC won a 35-year production sharing contract to develop the Libra pre-salt oil field in the Santos Basin offshore Brazil. Libra is located in block BM-S-11 in 6,500 feet of water and is estimated to hold as much at 12 billion barrels of oil. Additional appraisal will be needed to determine the best development scenario and to confirm production rates that are currently estimated at 1.4 MMbopd. Petrobras will serve as the operator with a 40 percent stake on behalf of its partners Shell (20 percent), Total (20 percent), CNPC (10 percent) and CNOOC (10 percent).
Europe – North Sea
Oct 24, 2013 – Drilling results at Eni’s Bonna prospect in the Barents Sea proved to be disappointing. Well 7016/2-1 was drilled by the Scarabeo 8 (UDW semisub) to a depth of 13,205 feet. The well was drilled to investigate the possibility of gas in the Eocene and Paleocene reservoirs of the Sotbakken Group. No reservoir-quality rocks were encountered and the well has been declared dry.
Project Details: Bonna
Asia – SouthEast
Oct 24, 2013 – Neon Energy announced the spud of the Ca Ngu-1 exploration well in Block 120 offshore Vietnam. The objective of the well is to prove the presence of hydrocarbons in Pliocene clastic and Miocene carbonate reservoirs. Block operator ENI secured the Songa Mercur (mid-water semisub) to drill the well in 885 feet of water to a target depth of around 4,900 feet. If successful, the well could de-risk the nearby Rua Bien and Ca Lang prospects. Block 120 partners consist of ENI (50%), Neon Energy (25%) and KrisEnergy (25%).
Project Details: Ca Ngu
Oct 24, 2013 – Subsea tree installation, well clean-up and flow testing of the Galoc-6H development well have successfully been completed at the Otto Energy-operated Galoc field. Galoc-6H flowed at a stable rate of 3,800 bopd on a 56/64-inch choke with a flowing tubing pressure of ~570 psi. These results were constrained by the testing equipment onboard the Ocean Patriot (mid-water semisub). Once tied into production facilities, Otto expects normal production from the well to reach 4,000 to 6,000 bopd. The 5H and 6H wells were drilled as part of the Phase II development plan which aims to increase field production to 12,000 bopd. Phase II production is scheduled to begin in November 2013.
Project Details: Galoc
S. America – Other & Carib.
Oct 25, 2013 – French supermajor Total announced its decision to move forward with the development of the Vega Pleyade gas and condensate field offshore Argentina. The field is located in the Cuenca Marina Austral 1 (CMA-1) concession that Total has operated since 1978. Development consists of installing a new production platform in about 160 feet of water. Three production wells will be drilled from the platform and produced gas will flow through 48 miles of subsea pipeline to a treatment plant at Rio Cullen. In a separate initiative, Total will begin a drilling campaign in 2014 aimed at boosting production from the Carina field and providing additional appraisal in CMA-1. Total owns a 37.5 percent stake in the concession. Its partners include Wintershall (37.5 percent) and Pan American Energy (25 percent).
Project Details: Vega Pleyade
Oct 25, 2013 – Drilling operations are complete at the Eni-operated Evans Shoal North-1 appraisal well. The well, located in the Timor Sea, was drilled by the Ensco 104 (400′ ILC) to a depth of almost 13,000 feet. Results indicate that the Evans Shoal North-1 reservoir is in communication with the reservoir encountered while drilling Evans Shoal-2. Eni conducted a production test and achieved a constrained rate of 30 MMscfd. The operator estimates the Evans Shoal field to contain at least 8 Tcf of in place gas resources and remains committed to establishing a fast-track development in the area. Eni’s partners in the field include Shell (32.5 percent), Petronas (25 percent) and Osaka Gas (10 percent).
Project Details: Evans Shoal
Oct 25, 2013 – ExxonMobil announced the start of production from its Kipper Tuna Turrum (KTT) project in the Bass Strait. Gas is now being produced at the Tuna field and oil is flowing from Turrum to the Marlin B production platform. At $4.3 billion, KTT is the largest domestic oil and gas development on Australia’s eastern seaboard. Production startup from the Kipper field is expected to commence in 2016.
Project Details: Kipper Tuna Turrum (KTT)
Drilling contractor Pacific Drilling S.A. has announced that Total S.A. has elected to exercise a one-year option to extend the firm contract term for the Pacific Scirocco to January 2015.
The contract provides for a further option, to be exercised at the client’s discretion by April 7, 2014, which could result in two additional years of contract term at a higher dayrate.
The additional one year term increases the drillship’s backlog by approximately $180 million, bringing the company’s total contract backlog as of April 9, 2013, to approximately $3.4 billion. The additional extension for two years would add a further $364 million backlog if exercised.
The Pacific Scirocco is capable of operating in water depths of up to 12,000 feet and drilling wells 40,000 feet deep.
Total announces a significant oil discovery at its North Platte prospect on Garden Banks Block 959 in the deepwater Gulf of Mexico. The discovery well encountered several hundred feet of net oil pay in Lower Tertiary sands which included several high-quality intervals.
Total estimates this discovery can have a potential of several hundred million barrels of oil. Further appraisal will be needed to confirm its size and commerciality.
“The North Platte discovery represents another example of Total’s bold exploration strategy targeting large exploration opportunities. It also demonstrates the efficiency of our alliance with Cobalt signed in 2009,” said Marc Blaizot, Total’s Senior Vice President Exploration.
Total is in a strategic alliance with Cobalt International Energy to explore for oil in the Deepwater Gulf of Mexico. The North Platte discovery is the first Lower Tertiary Wilcox formation well drilled by the Alliance. The results of the well confirm the northern extension of the Wilcox formation and the presence of liquid hydrocarbons. Therefore, this validates the major potential of this new exploration area of the Gulf of Mexico in which Total holds a substantial acreage position with several follow-on prospects.
North Platte is located in a water depth of approximately 4,400 feet (1,340 m) and was drilled to a total depth of approximately 34,500 feet (10,520 m). Total holds a 40% interest in the North Platte discovery along with Cobalt (60%, operator).
TOTAL E&P Australia (Total) has signed up to use AGR’s Riserless Mud Recovery (RMR®) system. The contract is for two exploration wells to be drilled over the next year in the Browse Basin off North West Australia.
Bernt Eikemo, AGR’s Vice President of the Enhanced Drilling Solutions (EDS) division (Asia Pacific), said: “AGR is delighted to be part of Total’s drilling team during the forthcoming exploration campaign. We hope that this is the start of a long, successful relationship with Total E&P Australia.”
He added: “Our previous experiences with several operators in the Browse Basin and the North West Shelf have shown that unconsolidated sand formations become much more benign when drilled with RMR® using a proper mud system.”
RMR® has been used by Total on several other projects internationally but this is the first time that the operator has used the system in Australia.
The main reason for using RMR® on these wells is to be able to drill through the unconsolidated sands of the Grebe Formation. It is renowned for stuck-pipe problems when drilling riserless using seawater and sweeps.
RMR® (system example attached) enables the use of weighted, engineered mud in the top-hole section. All mud and cuttings are returned to the rig with no discharge to the seabed. The top-hole section can be drilled more safely, quickly and with less impact on the environment.
RMR®, together with its sister technology the Cutting Transportation System (CTS™), has been deployed on more than 500 wells worldwide to date.
According to the Seadrill’s Fleet Status Report for May, Total has hired the rig on a three-month contract. The contract, expiring in mid-July, will bring approximately $12 million to Seadrill.
Total operates the Yadana field (31.2%). Located on offshore Blocks M5 and M6, this field produces gas that is delivered mainly to PTT (the Thai state-owned company) to be used in Thai power plants.
The Yadana field also supplies the domestic market via a land pipeline and, since June 2010, via a sub-sea pipeline built and operated by Myanmar’s state-owned company MOGE.
Following the completion of drilling operations in Myanmar, the rig will leave south-east Asia in which it has been operating since 2010. West Callisto will move to Middle East to commence drilling operations offshore Saudi Arabia under a three-year contract with Saudi Aramco. The drilling program is scheduled to start in September 2012
- Seadrill Secures Contract for Jack-Up Rig West Callisto Offshore Saudi Arabia (worldmaritimenews.com)
- Seadrill Expects Stronger Second Quarter after Robust 1Q 2012 (mb50.wordpress.com)
- South Korea: Seadrill Confirms Samsung Drillships Contracts (mb50.wordpress.com)
- Strong Demand for UDW Drillships Spurs Seadrill to Order One More from SHI (South Korea) (mb50.wordpress.com)
- Seadrill Orders Harsh Environment Rig in South Korea (mb50.wordpress.com)
- Ezion to Provide Service Rig for Operations Offshore Myanmar (mb50.wordpress.com)
April 14, 2012 10:27 pm by Jude Webber
Any hostile moves on YPF, the Spanish-controlled oil company, by the pro-nationalisation government in Buenos Aires could have implications that go way beyond the companies and investors at the heart of this bitter tug-of-war.
Why? Because Argentina is sitting on what geologists and energy experts widely agree is one of the world’s most attractive reserves of unconventional gas and oil – known as shale – which are trapped deep in the bedrock below ground.
Shale is potentially a very big deal indeed. It turned the US from energy importer to exporter – something that Argentina, which spent $9bn importing fuel last year, ought to take note of.
Argentina has about a third of the US shale reserves, but they are less deep (which makes them cheaper and easier to access), seams are two to three times thicker than in the US and, for now at least, Argentine shale is concentrated in the Vaca Muerta (Dead Cow) formation, rather than being spread out across the country.
So all other things being equal, shale producers should be brushing up their Spanish and heading south. Several big players – including ExxonMobil, Total and Apache – and smaller companies already have. But it is YPF which has the biggest acreage, and it estimates that as much as $250bn will be needed to develop a viable shale industry over the next decade.
No one’s pockets are that deep, so partnerships are the way to go. Except that regulatory concerns are raising red flags before investors’ eyes now.
YPF has been publicly criticised, stripped of a string of concessions after being accused of underinvestment and now the government is analysing how to give the Argentine state a bigger role in the company – something that, according to some proposals circulating in the government, could translate into the expropriation of as much as 50.01 per cent of the company.YPF is currently controlled by Repsol of Spain, which has 57.43 per cent, and 25.46 per cent is in the hands of the Eskenazi family’s Petersen Group. Just over 17 per cent is traded on stock markets.
So enthusiasm among potential new players in the shale sector – where some were prepared to invest as much as $10,000 to $12,000 per hectare, according to industry sources – is screeching to a halt. “This is damaging shale (prospects), of course,” Alieto Guadagni, a former energy secretary, told beyondbrics.
The government has been berating YPF for what it perceives as a failure to invest enough, yet the concerns its nationalization dream are raising risks reducing investor appetite – which is perverse. And if concerns over contracts were not enough to dampen investors’ spirits, the prospect of partnering with a state that likes fast results and dislikes repatriation of dividends may give pause for thought.
What is worse is that the shale prospects represent energy that Argentina badly needs. Underinvestment in the sector, analysts and industry players say, is the direct result of a regulatory regime that keeps prices in Argentina well below the international market.
As Guadagni put it, Argentina pays domestic gas producers some $2.8 per million British Thermal Units, yet shells out some $11 per million BTU for gas from Bolivia (produced, ironically, by Repsol YPF), and some $17 for liquefied natural gas to plug its huge energy deficit.
Meanwhile, the cost to Argentines for their domestic gas is about 50 US cents per million BTU of gas, and drivers of vehicles that run on compressed natural gas pay around $1.
“The big question is whether these plans for YPF will improve or worsen Argentina’s prospects for recovering its energy self-sufficiency,” Guadagni said.
Argentina had a $3bn energy surplus in 2006. This year, Guadagni reckons the deficit will be $6bn to $7bn, ballooning to $12bn in 2013. Argentina’s policy of cheap domestic energy to stoke demand and economic growth worked well after the country’s default of nearly $100bn in 2001. But it isn’t working now.
- Repsol YPF ups Argentine shale potential (mb50.wordpress.com)
- Spain warns Argentina over energy nationalisation (1oneday.wordpress.com)
- Argentina plots next moves in bid to control YPF (sfgate.com)
- Repsol YPF ups Argentine shale deposit potential (seattlepi.com)
- YPF Said to Lose Oil Partners as Government Cracks Down (businessweek.com)
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.
- Nine Oil Firms Table Bids for Ronda Uruguay II (mb50.wordpress.com)
The company said the gas was originating thousands of meters below the sea bed, which engineers said might mean that a relief well – one possible option to stop the leak – could take months to drill.
“The leak is from a (gas) well that was plugged one year ago and from a rock formation in about 4,000 meters depth,” a company spokeswoman in Aberdeen said on Thursday.
A flare needed to relieve pressure in the platform by purging excess gas has continued to burn less than 100 meters from the leak, and engineers said changes in wind and weather could lead to an explosion.
“The wind is pushing the gas cloud in the opposite direction (from the platform). At this time, the circumstances are rather favorable,” Jacques-Emmanuel Saulnier, head of communication at Total said in an interview published on Total’s website.
“A gas cloud is always a fire hazard,” he added.
Total kept two fire-fighting ships in a state of readiness outside a two-mile exclusion zone, which was set up to protect marine traffic, a Total spokeswoman said.
The company has also brought in a robot vessel, not yet deployed, to scan the sea bed for signs of spillage, she said.
Total has not yet found a way to stop the gas leak. A team of international engineers assembled by the embattled French oil company are drawing up plans to tackle the leak and prevent the flare from coming into contact with the gas cloud, the spokeswoman said.
The platform is currently off limits to the engineers, however, given the toxic and explosive plumes pumping out of the wellhead.
The leak started on Sunday and forced the evacuation of all 238 workers from the platform, which sits in waters less than 100 metres deep and 240 km (150 miles) off the east coast of Scotland.
PRESSSURE SEEN FOR RELIEF WELL
Total warned on Tuesday it could take six months to halt the flow of gas. The company previously stated it hoped the leak would die down from natural causes as reservoir pressure drops.
“What we know is that the leak is not coming from a well dug by Total but from a naturally occurring pocket of gas located just above one of our wells,” said Total’s Saulnier.
The depth of the non-producing reservoir that is feeding gas to the Elgin platform via compromised layers of piping suggests, however, there is more gas present rather than less, piling pressure on Total to drill a relief well, an engineer with knowledge of the matter said.
Relief drilling would require boring through 4 kilometers of rock with painstaking mathematical precision, because it must intercept the gas pocket at exactly the right point, requiring constant alterations in course, the engineer said.
The leak, one of the biggest in the North Sea for decades, could well inspire tougher safety regulation in due course, according to experts. Britain’s health and safety watchdog said it was considering launching an investigation into the incident, while union officials said the frequency of offshore safety lapses had become intolerable.
Memories are still raw in the North Sea industry of the Piper Alpha platform fire 24 years ago, which killed 167 people in the world’s deadliest offshore oil disaster and led to a major regulatory overhaul.
Total as well as UK authorities have described the expected environmental impact from the plume of gas and a spreading sheen of light oil on the water as “minimal”, although environmental experts said much of the gas “cocktail” would be either flammable or poisonous at close quarters.
Total’s shares have lost about 9 percent in the wake of the incident. They were trading at 37.63 euros at 1305 GMT.
Analysts said the French oil major could face costs of up to $10 billion if its North Sea gas leak leads to an explosion and nearly $3 billion if it takes months to fix.
However, Jefferies securities and investment bank said in a research note that data that had emerged on the spill, which “has further convinced us that the spill consequences should be less than the most pessimistic market estimates and hence that the US$9.7 billion sell-off in the stock since Monday is overdone”.
- Fitch: Total Gas Leak ‘Not Another Deepwater Horizon’ (mb50.wordpress.com)