Statoil and co-venturer ExxonMobil have announced the results from their first drill stem test in the Tanzania Block 2 offshore discoveries.

The data acquired is important to reduce technical uncertainties in a possible future Tanzania offshore and LNG development.
The Zafarani-2 operation tested two separate intervals and flowed at a maximum of 66 million standard cubic feet of gas per day, constrained by equipment, and confirmed good reservoir quality and connectivity.

The drill stem test operation was performed through a re-entry in the Zafarani-2 well, in 2,400 meters water depth and approximately 80 kilometers off the coast of southern Tanzania.

"The ongoing appraisal program is crucial to firm up the design and development basis for bringing gas to shore and a first phase onshore LNG project in Tanzania," says Øystein Michelsen, Statoil's Tanzania country manager.

"We are now working constructively with our co-venturer ExxonMobil, Blocks 1, 3 & 4 and the Tanzanian authorities to progress the plans for a joint LNG plant development."

The production well rate potentials are estimated to be higher than the equipment constrained rates obtained during the test. The Zafarani-2 operation will be followed by the appraisal well Zafarani-3, which concludes the planned appraisal in the Zafarani reservoir, the cornerstone for a field development in Tanzania Block 2.

The Zafarani-2 well test announcement follows the Mronge-1 discovery made in December 2013, which was the fifth discovery in Block 2 and brought the natural gas in place volumes up to 17-20 trillion cubic feet (Tcf)*.

The Mronge-1 was preceded by three successful high-impact gas discoveries during the first drilling phase with Tangawizi-1, Zafarani-1 and Lavani-1, and a deeper discovery in a separate reservoir in Lavani-2.

Statoil operates the license on Block 2 on behalf of Tanzania Petroleum Development Corporation (TPDC) and has a 65% working interest, with ExxonMobil Exploration and Production Tanzania Limited holding the remaining 35%.

Statoil has been in Tanzania since 2007, when it was awarded the operatorship for Block 2.

(*1 Tcf =180 million barrels of oil equivalent)

Noble Energy, Inc. (NYSE: NBL) has announced the signing of a gas sales agreement between NBL Eastern Mediterranean Marketing Ltd., the Arab Potash Company ("Arab Potash"), and the Jordan Bromine Company ("Jordan Bromine"), both of which are located in Amman,

Jordan. Under terms of the agreement, Noble Energy will supply natural gas from the Tamar field, offshore Israel, to Arab Potash and Jordan Bromine for use in their facilities near the Dead Sea. Natural gas sales are anticipated to commence in 2016, once minimal required pipeline infrastructure has been completed. The agreement is for an initial term of 15 years and a total gross contract quantity of approximately 66 billion cubic feet of natural gas. The price for the natural gas sold will be based on a floor price of at least $6.50 per thousand cubic feet of natural gas with upside linked to Brent crude oil prices. Gross revenues are estimated at $500 million, with actual sales dependent on final purchased quantities and oil prices at the time of sale.

Keith Elliott, Noble Energy's Senior Vice President, Eastern Mediterranean, commented, "The execution of this agreement evidences the growing regional opportunities for our natural gas and brings forward value for the Tamar asset. We have now signed the first regional export agreements for both Tamar and Leviathan, and we are in a number of additional negotiations to sell significant quantities of natural gas from both fields to multiple customers."
Finalization of the purchase and sales agreement is subject to necessary and customary conditions and regulatory approvals.

Noble Energy operates Tamar with a 36 percent working interest. Other interest owners are Isramco Negev 2 with 28.75 percent, Delek Drilling with 15.625 percent, Avner Oil Exploration with 15.625 percent, and Dor Gas Exploration with the remaining four percent. The Tamar field has an estimated 10 trillion cubic feet of discovered natural gas resources.

Shell has announced it has begun production from the Mars B development through Olympus – the company's seventh, and largest, floating deep-water platform in the Gulf of Mexico. It is the first deep-water project in the Gulf to expand an existing oil and gas field with significant new infrastructure, which should extend the life of the greater Mars basin to 2050 or beyond. Combined future production from Olympus and the original Mars platform is expected to deliver an estimated resource base of 1 billion barrels of oil equivalent (boe)

"With two large platforms now producing from the deep-water Mars field, this project demonstrates our deep-water project delivery and leadership," said John Hollowell, Executive Vice President for Deep Water, Shell Upstream Americas. "We safely completed construction and installation of the Olympus platform more than six months ahead of schedule, allowing us to begin production early from the development's first well. Olympus is the latest, successful start-up of our strong portfolio of deep-water projects, which we expect to generate substantial value in the coming years. Deep water will continue to be a core growth opportunity for Shell." 

Image credit: Shell

In addition to the Olympus drilling and production platform, the Shell Mars B development (Shell 71.5% operator, BP 28.5%) includes subsea wells at the West Boreas and South Deimos fields, export pipelines, and a shallow-water platform, located at West Delta 143, near the Louisiana coast. Olympus sits in approximately 945 metres (3,100 feet) of water. Using the Olympus platform drilling rig and a floating drill rig, additional development drilling will enable ramp up to an estimated peak of 100,000 boe per day in 2016. The Mars field produced an average of over 60,000 boe per day in 2013.

Also in the Gulf of Mexico, progress on the 50,000 boe/d Cardamom project (Shell 100%) continues toward a 2014 production date, and work is underway on the 50,000 boe/d, deep-water Stones development (Shell 100%) following the final investment decision last May.

• The Olympus platform is located in Mississippi Canyon in approximately 945 meters (3,100 feet) of water.
• Olympus is positioned within a few miles of two other production platforms, Mars and Ursa.
• The Olympus tension-leg platform (TLP) has 24 well slots and a self-contained drilling rig.
• The Mars B development is located about 210 kilometers (130 miles) south of New Orleans.
• The Mars B development involved more than 25,000 personnel in 37 states, during the construction phase.
• 192 people will live and work on the Olympus platform.
• Shell discovered the Mars field in 1989; production began in 1996.
• The development's reservoirs are located at a subsurface depth of 3,050 to 6,700 meters (10,000 to 22,000 feet), which is approximately 3 to 7 kilometers (2 to 4 miles), below the sea floor.

The Azerbaijan International Operating Company (AIOC), operated by BP, announced on Wednesday the start-up of oil production from the West Chirag platform as part of the Azeri-Chirag-Gunashli (ACG) field development in the Azerbaijan sector of the Caspian Sea. Start-up of the West Chirag platform completes the Chirag Oil Project (COP) sanctioned in 2010.
West Chirag production began from one of the pre-drilled wells - J05, on 28 January. The oil will first pass through the newly installed processing facilities on the platform and then will be exported to the Sangachal Terminal via a new in-field pipeline linked to an existing 30" subsea export pipeline. Production will increase through 2014 as the other pre-drilled wells are brought on line.

Gordon Birrell, BP's Regional President for Azerbaijan, Georgia and Turkey, said: "The start-up of COP marks a major milestone in the development of the super- giant ACG field. West Chirag is the eighth world-class offshore platform that we have built and operated in a safe and efficient manner in the Caspian. To date the ACG field has produced over 2.3 billion barrels of oil and with future continual major investments in new technologies and facilities, like the one we have today started up, it will continue to produce as a world-class reservoir for many decades. BP as the operator of the ACG field and our partners are committed to continuing the efforts that are expected to take us step by step towards optimization of production and maximization of the field recovery. We believe COP represents a big step forward towards stabilizing ACG's production and increasing recovery by drilling more wells from the new West Chirag facility.

"I would like to take this opportunity to thank the thousands of people, mostly from Azerbaijan, who built and installed the subsea pipelines, jacket and topsides unit of the new platform, for their dedication and outstanding performance over the past four years. I would also like to congratulate the government, our partners, employees, all the contractors, suppliers, and everyone else involved on this tremendous achievement. I would like to specifically highlight the outstanding performance of ACG's project, drilling, and operations teams in safely achieving First Oil. This demonstrates our ability to continue the impressive track record of planning, construction, and operations delivery in the Caspian Sea".
The West Chirag platform has been installed at a water depth of about 170 metres between the existing Chirag and Deepwater Gunashli platforms. The design oil capacity of the new platform is 183 thousand barrels per day. The gas export capacity is 285 million standard cubic feet per day.

CG participating interests are: BP (operator – 35.8%), SOCAR (11.6%), Chevron (11.3%), INPEX (11%), Statoil (8.6%), ExxonMobil (8%), TPAO (6.8%), ITOCHU (4.3%), ONGC Videsh Limited (OVL) (2.7%).

The project for joint seismic acquisition in the southeastern Barents Sea has been joined by 16 new companies. A total of 33 companies are now part of this project, which will secure good data quality and low acquisition costs.

Illustration of seismic acquisition. (Photo: Ole Jørgen Bratland)

A joint acquisition of data will also limit any possible negative consequences for the fishing industry.
The recently opened southeastern Barents Sea is part of the 23rd licensing round on the Norwegian continental shelf in 2014. At the request of the Norwegian Ministry of Petroleum and Energy (OED), the Norwegian Oil and Gas Association launched an initiative for a joint project relating to acquiring 3D seismic data from blocks in this area. Statoil took on the operator role for the acquisition.

On 10 December last year, 17 companies joined the project as early participants. A further 16 companies followed suit after the OED on 14 February circulated a proposal regarding block announcements for public consultation.

A doubling of the number of companies in the project shows that the initiative enjoys solid industry support. It is a project that will further reduce costs while ensuring good quality data by utilising the companies' concerted competencies.

In March the project will announce the awarding of contracts and present further plans for the acquisition.

List of companies participating in the project:

Early participants:
BP , Chevron, 
ConocoPhillips, 
Det Norske Oljeselskap, 
ENI ,
GDF Suez, 
Idemitsu, 
Lukoil,
Lundin, 
A/S Norske Shell, PGNiG, 
Repsol , Spike, 
Statoil , Suncor, 
VNG , 
Wintershall

New participants:
Bayern Gas,
BG, Dong , Edison, 
E.ON, 
Explora Petroleum, ExxonMobil, Faroe Petroleum, Inpex, 
KUFPEC,
MOECO, 
OMW, 
RN Nordic Oil, 
RWE Dea, 
Total, 
Tullow Oil

Statoil and the partners in the Johan Sverdrup field have decided on a concept for the first development phase. The partners have agreed on a field center consisting of four installations and power from shore.

Johan Sverdrup is among the largest oil fields on the Norwegian shelf, and will at peak contribute with 25% of the production from the Norwegian shelf. The giant field is expected to start production in late 2019. The field lifetime will be 50 years, with an anticipated plateau production of 550,000-650,000 barrels of oil equivalent/day (boe/d) field capacity (Statoil share ~40%).
The partners have decided on power from shore for the Johan Sverdrup field in the first phase, which will reduce total CO2 emissions from the Utsira High area by 60-70%.

"This is historic. We have not made a concept selection for a field this size since the 1980s," says Arne Sigve Nylund, executive vice president for development and production in Norway.

Establishing a field center 
The field will be developed in multiple phases. The design capacity of the first phase is 315,000 barrels of oil equivalents per day field capacity (Statoil share ~40%) with an expected production between 315,000 and 380,000 boe/d in the early phase. Pre-drilling of wells will contribute to a rapid production ramp-up.
"The ambition is a recovery rate of 70% for the full field," says Øivind Reinertsen, senior vice president of the Johan Sverdrup field.

Investments in the first phase are estimated at between NOK 100-120 billion. These include the field center, wells, export solutions for oil and gas, and power supply. The estimates also include contingencies and provisions for market adjustments. In addition, the first phase will facilitate measures for improved oil recovery.

The partners are working continuously to lower the investment level for the first phase.

The field center in the first phase comprises a process platform, drilling platform, riser platform and living quarter, and has been designed so as to facilitate future development. The installations have steel jackets that are linked by bridges. The water depth is approximately 120 meters in the area.

Power from shore 
Johan Sverdrup phase 1 will be supplied with power from shore with a transformer on Kårstø delivering direct current to the riser platform, ensuring an estimated 80 MW.

As part of the plan for development and operations, scheduled to be delivered in early 2015, alternative power solutions for the future phases will be described. One of the alternatives will be power from shore to the whole Utsira High area based on updated power requirements.

"This alternative, if selected, has the potential to capture more than 90% of the total CO2 emissions from this area," says Reinertsen.
Export solutions 
The export solution for oil and gas from Johan Sverdrup is based on transport to shore through dedicated pipelines. The oil will be transported to the Mongstad terminal in Hordaland county.

The gas will be transported via Statpipe to Kårstø in Rogaland county for processing and transport onward.

"Johan Sverdrup is the result of 40 years of development and activities on the Norwegian shelf. This is the opportunity to advance history several steps," summarizes Nylund.
Facts about the Johan Sverdrup field (PL 265, PL 501 and PL502)

• Johan Sverdrup is an oil field.
• Johan Sverdrup consists of a combined discovery which makes up one field.
• Location: Utsira High in the North Sea, 140 kilometers west from Stavanger.
• The water depth is 120 meters, and the reservoir depth is 1,900 meters.
• We expect approval of the plan for development and operation (PDO) during the Norwegian Parliament's (Stortinget) spring session in 2015.
• Production start is expected at the end of 2019.
• The field has a production horizon beyond 2050.
• The first phase is the establishment of a field center consisting of four platforms.
• Oil transport via pipeline to the Mongstad terminal in Hordaland, and gas transport to Statpipe, and then further to the Kårstø processing plant in northern Rogaland.
• The field will receive power from land.

Partners:

PL 501: Lundin Norway (operator - 40%), Statoil (40%), Maersk Oil (20%)
PL 265: Statoil (operator - 40%), Petoro (30%), Det norske oljeselskap (20%), Lundin Norway (10%)
PL 502: Statoil (operator – 44.44%), Petoro (33.33%), Det norske oljeselskap (22.22%)

The Bureau of Safety and Environmental Enforcement (BSEE) confirmed t on Saturday that the flow of natural gas from the A-7 well, Vermilion Block 356, has been stopped by pumping weighted drilling fluids into the well. The well is located in the Gulf of Mexico, approximately 108 miles southwest of Lafayette, Louisiana.

While the natural gas flow has stopped, there is additional work required to secure the well that includes setting barriers to ensure that no natural gas is released. Barriers also ensure safety of the well and personnel during operations. BSEE will review all procedures for efforts to secure the well.
BSEE approved EnVen's procedures for the pumping operation, which began at 4:45 p.m. CST January 31, 2014. The well was monitored overnight to ensure that the flow did not resume.

BSEE is leading the coordinated response with the Coast Guard. BSEE will investigate the incident.

BACKGROUND: The operator, EnVen, reported Thursday that it was drilling from the jack-up rig, Rowan Louisiana, when the well began to flow natural gas. The flow was diverted overboard and work began to stop the flow. No visible sheen has been reported. All production from the A-Platform, which is located under the jack-up rig, remains shut-in. As a precaution, personnel onboard the platform were evacuated. No injuries have been reported.

Angola LNG has announced the sale of its first LPG cargo from its plant in Soyo, the facility built to create value from Angola's offshore gas resources.
The first cargo was sold to Sonangol, Angola's state oil & gas company, on a Free on Board (FOB) Soyo basis and shipped by the LPG carrier BW Broker. All LPG and condensate products have been committed for sale to the shareholder affiliates of Angola LNG.

The LPG and condensate jetty was commissioned immediately prior to commencement of loading operations. Commissioning included the testing of safety devices, mooring arrangements and loading arms.

Commenting on the first cargo Artur Pereira, CEO, Angola LNG Marketing, said: "In addition to LNG production for international markets propane, butane and condensate production at Angola LNG is an important part of our operational and commercial activity. Our LPG and condensate production will help to supply both domestic and export markets with their energy needs."

In addition to its LNG facilities Angola LNG's liquids infrastructure at its production plant in Soyo includes storage tanks for 88,000 m3 of propane, 59,000 m3 of butane, and 108,000 m3 of condensate. It has a jetty dedicated to propane, butane and condensate loading and a second jetty for pressurised butane loadings which will serve the domestic market.

Today's announcement marks a further milestone in the continued development of Angola's oil and gas resources and provides a new source of energy for Angola and export markets.

Angola LNG Limited is an incorporated joint venture between Sonangol, Chevron, BP, ENI and Total that will gather and process gas to produce and deliver LNG and NGLs. The plant has an expected life of at least 30 years.

Angola LNG will gather, process, sell and deliver 5.2 million tons per year of LNG - plus natural gas, propane, butane and condensate - from its plant in Soyo, Angola; one of the world's most modern LNG processing facilities. Angola is the second-largest oil producer in sub-Saharan Africa. Historically associated gas has been flared or re-injected into the reservoirs, but Angola LNG provides a solution to reduce emissions and establish a new source of clean energy.

Shareholders of Angola LNG Limited are Sonangol (22.8%), Chevron (36.4%), BP (13.6%), ENI (13.6%), and Total (13.6%).

At $10bn the Angola LNG infrastructure is one of the largest ever single investments in the Angolan oil and gas industry. Offering a dedicated fleet of seven LNG vessels and three loading jetties (LNG, liquids and compressed butane) Angola LNG's mission is to contribute to the elimination of gas

The Obama administration is expected to move closer this week to allowing new exploration for oil and natural gas in the Atlantic Outer Continental Shelf (OCS).

Surging oil and natural gas production onshore has sparked an energy and manufacturing revolution in America. But offshore, 87 percent of federal waters remain closed to energy exploration. A recent report projects big economic gains if we remove self-imposed obstacles and open the Atlantic OCS to responsible energy development.

Between 2017 and 2035, oil and natural gas development in the Atlantic OCS could:

·         Create nearly 280,000 new jobs along the East Coast and across the country

·         Generate an additional $195 billion in private investment on oil and natural gas activity

·         Contribute up to $23.5 billion per year to the U.S. economy

·         Add 1.3 million barrels of oil equivalent per day to domestic energy production, which is about 70% of current output from the Gulf of Mexico

·         Raise $51 billion in new revenue for the government

Seismic surveys, an advanced exploration technique used to locate potential oil and natural gas reserves below the ocean floor, are an essential first step. The Obama administration will publish this week an environmental study that could pave the way for the first seismic surveys of the Atlantic OCS in three decades.

Existing estimates of the oil and natural gas available in the Atlantic OCS are out of date. New surveys using state-of-the-art techniques and technology would provide a better understanding of the oil and natural gas resource potential in that area. Watch this video to learn how it works.

By allowing seismic surveys in the Atlantic and including the area in its upcoming five-year offshore leasing plan, the Obama administration can open the door to significant economic growth for the U.S. and Atlantic coastal states.

Offshore drilling contractor North Atlantic Drilling has agreed to purchase two next-generation GE Oil & Gas (NYSE: GE) SeaONYX^TM blowout preventer (BOP) control systems, upgrading control spreads on board NAD’s semi-submersible West Venture (left) and drill ship West Navigator. (right)

The SeaONYX BOP control system extends system availability by incorporating multiple redundancies and hot-swappable components to keep operations online. SeaONYX is built upon GE’s proven Mark VIe architecture, at work in more than 2,000 wind, hydroelectric and nuclear power installations worldwide.In addition to improved uptime performance compared to other controllers, SeaONYX is a keystone of GE’s predictive drilling management technology, which helps drillers to address issues before they occur.“Once SeaONYX is on board, the architecture is in place to incorporate a broad array of monitoring and intelligent systems that have the potential to virtually eliminate unplanned downtime,” said Chuck Chauviere, president of Drilling Systems—GE Oil & Gas. “Adding RamTel Plus provides detailed information on the ram BOP’s functionality, while the Drilling iBox can model this data to predict future performance. Armed with this data, the drilling contractor can plan condition-based maintenance at service intervals based around the drilling schedule. The predictivity that GE Oil & Gas delivers for operators means traditional break-fix maintenance can be replaced with a proactive, recommended maintenance model that has the potential to eliminate the lost drilling time that is unavoidable with the old model.”

Blowout preventers are critical pieces of drilling equipment that are used to isolate pressure in oil and gas wells during drilling or close the well entirely in an emergency. The SeaONYX BOP control system is available as an upgrade to existing GE BOP controllers and is included in all new GE Oil & Gas BOP stacks for floating drilling rigs.

In addition to improved uptime performance compared to other controllers, SeaONYX is a keystone of GE’s predictive drilling management technology, which helps drillers to address issues before they occur.

“Once SeaONYX is on board, the architecture is in place to incorporate a broad array of monitoring and intelligent systems that have the potential to virtually eliminate unplanned downtime,” said Chuck Chauviere, president of Drilling Systems—GE Oil & Gas. “Adding RamTel Plus provides detailed information on the ram BOP’s functionality, while the Drilling iBox can model this data to predict future performance. Armed with this data, the drilling contractor can plan condition-based maintenance at service intervals based around the drilling schedule. The predictivity that GE Oil & Gas delivers for operators means traditional break-fix maintenance can be replaced with a proactive, recommended maintenance model that has the potential to eliminate the lost drilling time that is unavoidable with the old model.”

Blowout preventers are critical pieces of drilling equipment that are used to isolate pressure in oil and gas wells during drilling or close the well entirely in an emergency. The SeaONYX BOP control system is available as an upgrade to existing GE BOP controllers and is included in all new GE Oil & Gas BOP stacks for floating drilling rigs.

Charles and David Koch of Kansas are the wealthiest individuals in America’s oil and gas sector, with a combined net worth of US$83 billion, according to a Wealth-X Top 10 list that includes billionaires from Texas, New York and Oklahoma.

Charles, Koch Industries’ chairman and CEO, and David, executive vice president, are the principal owners of the Wichita-based company founded by their father Fred in 1940. Charles and David Koch each own 42% of Koch Industries, which is involved in the manufacturing, refining and distribution of petroleum, chemicals, polymer and other materials.

Four billionaires from Texas appear on the list: Milane Frantz (one of two females on the list), Ray Hunt, Jeffrey Hildebrand and William Hunt. Kansas is home to three oil and gas billionaires, the two Koch brothers as well as Elaine Tettemer Marshall, who inherited her fortune from her late husband, Everett Pierce Marshall, (who had holdings in Koch Industries).

Below are the top 5 wealthiest individuals in America’s oil and gas sector:

With a combined wealth of US$83 billion, the Koch brothers make up over half of the total, combined net worth of the 10 billionaires on the Wealth-X list.

Wealth-X President David S. Friedman notes: “It's interesting to see how the Koch brothers are leveraging their wealth in the political arena and how Anschutz has leveraged his in the media and entertainment industries.  It's also interesting to note that oil-driven wealth in North Dakota is creating millionaires, but we have yet to see a significant increase in the ultra wealthy in that area.”

For the full list, visit http://www.wealthx.com/articles/2014/top-10-wealthiest-individuals-in-americas-oil-and-gas-sector/

Editors Note: Wealth-X considers an UHNW individual to be located in a city where that individual has a primary business address.

About Wealth-X


Wealth-X is the definitive source of intelligence on the ultra wealthy with the world’s largest collection of curated research on ultra high net worth (UHNW) individuals, defined as those with net assets of US$30 million and above. Headquartered in Singapore, it has 12 offices in five continents. (www.wealthx.com)

The Petrobras LNG Regasification Terminal in Bahia brings greater flexibility and assurances to natural gas supplies in Brazil, with regasification capacity now up to 41 million m³/day.

At precisely 1:13 pm on Friday (January 24, 2014), Petrobras added to the Brazilian gas pipeline network the first regasified LNG (Liquefied Natural Gas) from its new Regasification Terminal, located in Baía de Todos os Santos, Salvador, in the state of Bahia. The Bahia Regasification Terminal (TRBA) has a regasification capacity of 14 million m³/day of natural gas. With the new terminal now in operation, Petrobras' natural gas regasification capacity has risen from 27 million m³/day to 41 million m³/day, equivalent to almost one and half times the capacity to import gas from Bolivia.

The company is already operating the regasification terminals at Pecém (Ceará state) and Guanabara Bay (Rio de Janeiro state) with their respective regasification capacities of 7 million m³/day and 20 million m³/day of natural gas.

The LNG is imported from various suppliers around the world in order to meet the domestic demand for natural gas, with a view to providing greater flexibility and guaranteeing supplies, thereby increasing the country's energy security, which is essential to encourage new investment.

The TRBA involved an investment of around R$ 1 billion and is the country's third LNG regasification terminal. An ingredient of the federal government's Growth Acceleration Program (PAC), construction of the terminal was begun in 2012 and it was completed on time and generated 3,623 direct jobs in the region, while achieving a level of domestic content in its equipment and services of approximately 90%.

Stone Energy Corporation (NYSE: SGY) has announced exploration discoveries at its deep water Amethyst and deep gas Tomcat prospects. Stone operates and owns a 100 percent working interest in both discoveries.

The deep water Amethyst exploration well in Mississippi Canyon block 26 encountered approximately 90 feet of net hydrocarbon pay in one interval which suggests a commercial discovery. Analysis of logging, coring and fluid data confirmed the existence of natural gas, condensate and natural gas liquids in the pay zone (an estimated yield of 60-80 barrels of liquids per million cubic foot of natural gas). The interval has been placed safely behind pipe for a future completion. A full evaluation, including seismic and subsurface data integration, is needed before hydrocarbon quantities can be estimated and a specific development plan is sanctioned. A single or multi-well tie-back to Stone's 100 percent owned Pompano platform, located less than 5 miles from the discovery, is a likely development option.

The results at the deep gas Tomcat exploration prospect at West Cameron block 76 also suggest a commercial discovery with approximately 30 feet of net hydrocarbon pay in the Camerina interval. Well log analysis, combined with offset Camerina production history, would suggest the zone should produce rich natural gas with approximately 60 barrels of condensate per million cubic feet of natural gas as well as additional natural gas liquids volumes. Initial development plans call for a tie-back to a nearby Stone operated East Cameron block 64 production platform with production estimated to commence in second half of 2014.

Chairman, President and Chief Executive Officer David H. Welch stated, "It is a great start to the year to make discoveries at Amethyst and Tomcat, our two 100 percent working interest exploratory prospects. The close proximity of both prospects to Stone platforms should provide us with attractive development options and enhance the economic value of the discoveries. The knowledge and information gained from the Amethyst well will also be helpful in evaluating our existing portfolio of prospects in the Mississippi Canyon area where we expect to be an active player for the next several years."

The rigs remain on location at both Amethyst and Tomcat to conduct operations to prepare the wells for future production.

Brunei Shell Petroleum has awarded Maersk Drilling a four year contract for the jack-up rig Maersk Completer for operation offshore Brunei. The contract commences in November 2014 in direct continuation of its current contract with Brunei Shell Petroleum. The contract has options for extension up to a total of three years.

"We are very pleased to continue our cooperation with Brunei Shell Petroleum in Brunei. We see this contract as a recognition of our solid drilling performance and as a further strengthening of our relationship with Brunei Shell Petroleum," says Claus V. Hemmingsen, CEO of Maersk Drilling and member of the Executive Board of the A.P. Moller – Maersk Group.

While operating for Brunei Shell Petroleum, Maersk Completer has shown an excellent performance record, recognised by the award as Shell Jack Up of the Year in 2012 and 2013.
Maersk Completer is one of two Baker Marine 375ft jack-up rigs in Maersk Drilling's fleet. Maersk Completer has been operating in Brunei since it was delivered from Jurong Shipyard in 2007, and since November 2008, Maersk Completer has been operating for Brunei Shell Petroleum (BSP).

Total announces the sale of its 15% participating interest in the offshore Angola Block 15/06 to Sonangol E&P.


The transaction is valued at 750 million dollars and remains subject to customary approvals.

“The sale of our interest in Block 15/06 is in line with Total’s global strategy to actively manage its portfolio and focus its investment capability on core assets in which it has more material interests, such as Block 17 with the CLOV project currently under development and the future development of Kaombo on Block 32 in Angola” said Jacques Marraud des Grottes, Senior Vice-President Africa at Total’s Exploration and Production.



 Block 15/06



Block 15/06 is located approximately 350 km northwest of Luanda in deep offshore Angola and covers approximately 2,984 square kilometers, with a water depth ranging from 220 to 1,700 m.

The north-western hub of the block, currently under construction, is expected to produce in 2015 and a final investment decision for a north-east project is expected to be taken in 2014.

The block is operated by Eni (35%) with partners Total (15%), Sonangol (15%), SSI (a joint affiliate of Sinopec and Sonangol, 25%), Statoil (5%) and Falcon Oil Angola Investimentos (5%).



 Total Exploration & Production in Angola



Total has been present in Angola since 1953. In 2013, Total’s SEC* equity production amounted to 186,000 barrels of oil equivalent per day (boe/d). Most of this production comes from Blocks 17, 0 and 14. At the end of 2013, Total’s operated production was around 600,000 boe/d, making it the country’s leading oil operator.



Block 17, where the Group is operator with a 40% interest, is Total's main asset in Angola. The block contains four major hubs: Girassol-Rosa, Dalia and Pazflor, which are currently in production; and CLOV pooling the discoveries of Cravo, Lirio, Orquidea and Violeta. CLOV’s development was launched in 2010 and is expected to start-up in 2014.



Total is also operator of the ultra-deepwater Block 32, in which it holds a 30% stake. Twelve discoveries have confirmed the block's potential for oil production, and studies are underway for a development in the central southeastern sector of the block, the Kaombo development project.



In addition, the Angola LNG project (Total 13.6%), near Soyo, is bringing the country’s natural gas reserves to market. The LNG plant will initially be supplied with associated gas from fields on blocks 15, 17 and 18 and later on from gas fields on blocks 0 and 14.



In Angola, as in all its host countries, the Group ensures that health, safety and environment are paramount priorities. Moreover, Total is committed to developing the Angolan oil industry by recruiting and training local workforce. Total is strengthening the local economy through its ambitious “Angolanization” and technology transfer plan.

Total E&P Angola implements a transparent, wide-reaching corporate social responsibility process focused on three main areas: health, education and local economic development.


LGO announces that the Company has now started mobilization for the construction of the first drilling sites following the Certificate of Environmental Compliance ("CEC") for 30 new development wells having been formally issued by the Environmental Management Agency of Trinidad and Tobago.  The work at its 100% Goudron Field will start almost immediately and LGO expects to spud the first new well on Goudron since the 1980's as soon as the preparatory works are completed.

Highlights:

·    CEC to drill 30 new wells at the Goudron Field formally approved.

·    Goudron Field has 2P oil reserves of 7.2 million barrels ("mmbbls") and further contingent oil reserves of 63 mmbbls, with an oil-in-place of 127 mmbbls (2P).

·    The first new well, H-18E J-7, will be drilled to approximately 4,000 feet and is targeting net oil sands of 250 feet in the Gros Morne sandstones and a further 100 feet in the Lower Cruse sandstone.

·    Infrastructure improvements to handle the increase in oil production at Goudron are nearing completion.

·    An additional 2,000 barrels of oil sales capacity has also been approved with the CEC.

Neil Ritson, LGO Chief Executive, commented:

"The next phase of our re-development at Goudron is about to get underway.  This is a very exciting phase for the Company and the drilling of these new wells will result in a substantial increase in the Company's oil production.  The minimal facilities that were in place when LGO acquired the asset in 2012 have been significantly upgraded to support the 65 well reactivations carried out so far and the 30 new wells that we are about to drill.  The approval in this CEC of an additional 2,000 barrel sales tank is also critical to medium term growth."

Drilling Update

The 30 new wells approved for the Goudron Field will be targeting known productive intervals in the Goudron, Gros Morne and Lower Cruse sandstones. Each new well is expected to take 7 to 10 days to drill.  Well evaluation and final completion will be undertaken after the rig has been moved to the next well and initial production is planned to commence within 60 days of spudding each well.

A drilling contractor has been selected and other services are being contracted at this time.  The chosen rig is currently undergoing upgrade work and is expected to be available to mobilize to Goudron in late February 2014.

Drill pad construction contracts will now be awarded in conjunction with completing the access road repairs currently underway to accommodate the transport of heavy machinery. A permanent camp, including workshops, offices and off duty rest accommodation has been constructed and is currently being commissioned in readiness for the commencement of the drilling program.

Infrastructure improvement work at the field continues with the reactivation of Tank Battery Station No. 207 nearing completion where the existing tanks have been refurbished to provide an additional 1,000 barrels of storage and water treatment in preparation for the expected increase in oil production.

The first well, provisionally designated H-18E J-7, lies within an area of the field where unrecovered oil is expected to be present in the Gros Morne and Lower Cruse sandstones.  The Lower Cruse at a depth of 2,800 feet sub-sea is the primary target of the well, which will then be deepened to approximately 4,000 feet to ensure all productive horizons are intersected.  Based on the offset wells; including GY-188 (250 feet to the north-east) and GY-64 (170 feet to the north-west), net oil sand of 250 feet is prognosed in the Gros Morne and a further 100 feet in the Lower Cruse. 

LGO is now evaluating the merits of drilling the 30 wells in a continuous program.  Previously, only 2 wells were intended in the next phase to be followed by the balance of the wells after an evaluation phase, however, the deferred start, presence of adequate funding and various economies of scale suggest that a longer continuous drilling program will give improved economic returns.

Goudron Field Reserves

In July 2012, Challenge Energy Limited ("Challenge") independently assessed the Proven and Probable (2P) recoverable reserves from primary production, prior to new drilling, of 7.2 million barrels (mmbbls) and Proven, Probable and Possible reserves (3P) of 30.4 mmbbls.  Challenge's estimates are tabulated below.

It is anticipated that the execution of this 30 well development campaign will move the majority of the 2P reserves to the Proven category and a new competent persons report will be commissioned in the second quarter 2014, once new drilling results have been obtained.

No secondary or enhanced oil recovery, such as water-flooding, had been assumed in these previously reported reserves; although nearby analogous fields in Trinidad have had successful water-flood projects.  Overall recovery without water-flooding is estimated to be just 10% of the oil-in-place which has been computed to be up to 350 mmbbls in the 3P case.  Challenge recognizes a further 63 mmbbls of Contingent Resources associated with a future water flooding project.  If such a project was undertaken it is believed that the overall recovery factor would rise to about 30%.

IPSC with Petrotrin

LGO has a 100% working interest in the Incremental Production Service Contract ("IPSC") granted by the Petroleum Company of Trinidad and Tobago ("Petrotrin") which gives LGO rights to produce oil from the 2,875 acres (11.4 square km) Goudron Block down to 5,000 feet subsea.  The Goudron Field is be operated by Goudron E&P Limited, a wholly owned subsidiary of LGO.

The IPSC was effective from 18 November 2009 and had an initial term of 10 years. On 14 August 2013, LGO successfully concluded an agreement with Petrotrin to reduce substantially the overriding royalty rates associated with oil production from Goudron and to extend the contract by at least five (5) years to November 2024 in consideration for LGO undertaking additional drilling.

The revised IPSC agreement, effective from 1 August 2013, included a reduction of overriding royalty rates for existing and future production in order to incentivize further development and exploration in the Goudron Block.  The 30 well re-development program commencing in 2014 is a direct result of that agreement and will meet, and greatly exceed, the additional commitments made at that time. The new agreement provides that oil production between the First Tranche Oil, which is currently approximately 40 barrels per day ("bopd"), and a rate of about 150 bopd (reducing annually by 2%) will receive a relative reduction of approximately 20% in the overriding royalty paid to Petrotrin. Production above 150 bopd, which Goudron is already exceeding, has a more significant reduction equivalent to approximately 45% of the previously applicable rate at the current oil price.

Language was also included in the revised IPSC that, subject to mutual agreement on work programs, will allow the IPSC to be extended for a period of 5 years in 2019. This extension is significant as it will allow the Company to effectively instigate Enhanced Oil Recovery programs in order to bring the 30 mmbbls of Possible (P3) reserves and some of the 63 mmbbls of Contingent Resources in to Proven (P1) and Probable (P2) reserves over the coming years.

LGO holds a 100% interest in the Goudron Field and all such estimates therefore both gross and net to the Company.