Leak detection is a considerable challenge facing the industry and DNV GL has therefore taken the lead in establishing a new Joint Industry Project (JIP). Twenty key industry players are partnering to develop a best practice for designing and implementing offshore leak detection systems.

Over the last few years, following several oil releases, there has been an increasing focus by both operators and authorities on the environmental impact related to offshore oil and gas activities. This is especially an issue that needs to be addressed now since society's tolerance for leaks is dropping and we are moving into the Arctic and other environmentally sensitive areas. Hydrocarbon leak detection systems are a requirement on the Norwegian Continental Shelf but authorities around the world are also increasingly demanding such systems for new field developments.

There are various leak detection sensors available but they all have limited coverage and application areas. Some sensors will only detect gas, some cover a small area with high sensitivity while others cover a large area with low sensitivity. The challenge is to integrate these into a complete system that provides the required coverage and sensitivity while at the same time avoiding frequent false alarms.
In addition, leak detection methods and techniques have been available in the market for several years, but there are still gaps to be closed concerning the design, engineering, commissioning and operation of these systems to ensure their proper performance.
The industry is coming together to find the right solutions
Twenty companies and regulators are participating in DNV GL's Joint Industry Project (JIP) on Offshore Leak Detection.

According to one of the partners, Lundin Norway, there is a great need to further develop these systems. "Today, it's difficult to get a good system with a demonstrated track record that covers an entire field, both subsea and on the surface. There's a strong need for a common approach so that the operators and suppliers can jointly improve these systems. We also need to define reasonable specifications and requirements. It's equally important to consider how different technologies can be integrated into a system that is practical for the end user," says Arnljot Skogvang Company Rep at Lundin.

DNV GL's Business Development Manager for Subsea, Christian Markussen (photo), says: "I'm really glad to see the great participation from key industry players, but the JIP would benefit from having even more operators, integrators and subsea suppliers."

The Joint Industry Project is aiming high
Markussen explains that the overall aim is to ensure safe and environmentally sound operations by limiting hydrocarbon spills through detecting acute discharges, with a high level of certainty, at the earliest possible stage. A planned outcome will be a DNV GL Recommended Practice that addresses the leak detection system through all the lifecycle phases of offshore development projects. The project will define relevant functional requirements and general specifications for a leak detection system as well as developing a methodology for designing an integrated system, including surface and subsea technologies.

DNV GL is facilitating this JIP, combining industry experience with the competencies and expertise of the Subsea Technology and Environmental Risk Assessment & Technology sections at the DNV GL Oil & Gas office at Høvik, Norway.
Operators: Lundin, BP, ENI, Petrobras and GDF Suez
Integrators: FMC Technologies
Suppliers: NAXYS, Biota Guard, SonarDyne, VisSim, Stinger, Phase, Kongsberg, Norbit, Contros, Metas and KSAT
Observers: Norwegian Oil & Gas, Norwegian Ministry of Climate and Environment and the Petroleum Safety Authority Norway

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.

Petrobras announces that it has completed drilling wildcat well 1-BRSA-1205-RNS (1-RNS-158), located in deep-waters of the Potiguar Basin. The results confirm the discovery of intermediate oil (24º API), as previously announced to the market on December 17, 2013.

The well, informally referred to as Pitu, is located at a water depth of 1,731 meters, 55 km off the coast of the state of Rio Grande do Norte.
The well reached the total depth of 5,353 meters and detected a hydrocarbon column of 188 meters. A formation test was carried out, which confirmed the reservoir's satisfactory permeability and porosity.

Based on the results obtained, the consortium will proceed with the exploratory activities, with the aim of proposing a Discovery Evaluation Plan to Brazil's National Petroleum, Natural Gas and Biofuels Agency (ANP).

Petrobras is the operator of concession BM-POT-17, with an 80% interest, in partnership with Petrogal Brasil S.A., which holds 20%.

As a result of the on-going farm-out process and after obtaining the necessary approval from Brazilian authorities, BP Energy do Brasil Ltda will join as a concessionaire and the interests of the consortium members in BM-POT-17 will be as follows: Petrobras - 40% (operator), BP Energy do Brasil Ltda - 40% and Petrogal Brasil S.A - 20%.

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.

Proposal would strengthen oversight capacity for offshore oil and gas development under the President's all-of-the-above energy strategy

President Obama's fiscal year 2015 budget request for the Bureau of Safety and Environmental Enforcement (BSEE) is $204.6 million, a $2.0 million increase over the 2014 enacted level. The Administration's proposal would provide critically needed resources to further strengthen BSEE's regulatory and oversight capabilities for oil and gas development on the U.S. Outer Continental Shelf, as the Administration works to responsibly expand domestic energy production through the President's all-of-the-above energy strategy.

"The President's 2015 request lays a strong foundation for a sustainable regulatory program and provides the infrastructure necessary to ensure offshore oil and gas activities are conducted safely and in an environmentally responsible manner," said BSEE Director Brian Salerno. "The President's request will enhance our ability to keep pace with a dynamic industry as operators continue to pursue new and emerging technologies that enable them to develop our nation's energy resources in deeper water and frontier areas."

The 2015 budget proposal would enable BSEE to continue to bolster engineering, scientific and technical expertise and research needed to increase its capacity in multiple disciplines to adequately staff regulatory, safety management, structural and technical support as well as oil spill response prevention programs. The development of robust scientific information and the timely and thorough review of exploratory and production permits are critical components of BSEE's oversight responsibilities.

The President's budget furthers BSEE's strategic goals through a program increase of $905,000 to support enhanced review of emerging technologies, and expand project funding to validate technology, test protocols and analyze economic feasibility. The President's request will be offset by $123.6 million from BSEE collections, including $65.0 million from inspection fees, $50.4 million from rental receipts and $8.2 million from cost recovery fees.

The proposed 2015 budget will enable BSEE to continue to build a robust culture of safety, with a strong focus on risk reduction. The Bureau will bolster its capacity for analyzing data gained through incident reporting requirements, near-miss reporting, and real-time monitoring. BSEE will also work with the offshore industry to better understand their safety processes, so that in turn it can mitigate safety risks and reduce the likelihood of future incidents.
As part of this cooperative effort, BSEE will continue the development of the Ocean Energy Safety Institute in FY2015. The Institute will provide a program of research, technical assistance, and education that serves as a center of expertise in offshore oil and gas exploration, development and production technology. This expertise will be especially critical for frontier areas, such as high temperature/high pressure reservoirs, deepwater, and Arctic exploration and development.

By the end of 2013, there were 40 deepwater floating rigs drilling in the Gulf of Mexico, up from 37 at the start of the year. The Energy Information Administration projects offshore production will continue to grow from 2015 through 2040, as the pace of development activity quickens and new, large development projects, predominantly in the deepwater and ultra-deepwater areas of the Gulf of Mexico are brought into production. The 2015 budget request provides robust support that will enable the Bureau to keep pace with industry activity and the technology developments that are helping to drive this anticipated growth.

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)

President Obama's fiscal year 2015 budget request, announced today, includes $169.8 million to fund the Bureau of Ocean Energy Management (BOEM), which is charged with managing the Nation's offshore energy and mineral resources in a way that promotes efficient and environmentally responsible energy development through oil and gas leasing, renewable energy development, and a commitment to rigorous scientific studies. 

"BOEM’s priorities fully support the Administration's vision for creating growth and opportunities as we pursue our mission. Our modest increase in the President’s request reflects careful analysis of the resources needed to advance renewable and conventional energy, manage non-energy OCS mineral resources and invest in what’s needed to grow the economy." said BOEM Director Tommy P. Beaudreau.

The budget requests continued funding to fulfill BOEM's program implementation responsibilities, which include leasing and planning for conventional energy development through implementation of the Five Year Outer Continental Shelf (OCS) Oil and Gas Leasing Program, planning for individual lease sales and conducting post-sale review of companies' exploration and development plans.  BOEM also manages the development of offshore renewable energy resources - including implementation of the Secretary's "Smart from the Start" initiative to accelerate leasing in offshore wind energy areas off of U.S. coasts.

In support of both its conventional and renewable energy programs, BOEM conducts extensive analysis, including environmental review, resource assessment, and economic analysis.  Applied research through BOEM's Environmental Studies Program supports science-based decision-making.  

The budget proposes an increase of $2.9 million above the FY 2014 enacted level and a $3.4 million increase in net appropriations. This includes $2.5 million for a  programmatic environmental impact statement (EIS) for the 2017-2022 Five Year Program. The programmatic EIS is mandated by the National Environmental Policy Act and is required by the OCS Lands Act. Development of the EIS involves scoping, development of alternatives, Federal and state agency coordination, public comment, comment analysis and response, as well as final publication.

Additional details on the President's FY 2015 budget request are available online at http://www.doi.gov/budget/appropriations/2015/highlights/index.cfm.

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.