Deepwater startup adds new production from Chevron's growth queue

Chevron Corporation (NYSE: CVX) has confirmed that its Brazilian subsidiary and Petrobras have started crude oil production from Papa-Terra's floating production, storage and offloading vessel (FPSO) offshore Brazil.

"The startup of Papa-Terra is another important step toward meeting the growth target we've set for 2017," said George Kirkland, Chevron's vice chairman and executive vice president, Upstream.

"The successful development of Papa-Terra is the result of a robust partnership between Chevron and Petrobras that integrates the unique skills and expertise of both companies to deliver challenging projects and new energy production," said Ali Moshiri, president of Chevron Africa and Latin America Exploration and Production Company.

Chevron holds a 37.5 percent interest in the Papa-Terra field, while Petrobras, the project operator, has the remaining 62.5 percent. Located approximately 70 miles (110 kilometers) southeast of Rio de Janeiro at a water depth of approximately 3,900 feet (1,190 meters), Papa-Terra is a heavy oil development within Block BC-20 of the southern Campos basin.
Discovered in 2003, the Papa-Terra field development features the FPSO and the first tension leg wellhead platform in Brazil, which is expected to start production in 2014. Papa-Terra has installed capacity to produce 140,000 barrels of crude per day.

Imtech Marine has been awarded a second Advanced Support Agreement from Jack-Up Barge for 24/7 remote monitoring and maintenance of the systems installed by Imtech Marine on board the newbuild, self-elevating platform JB-118. This follows an earlier and similar contract for the JB-117, where Imtech Marine completed equipment installation in 2012 and subsequently started remote monitoring. The JB-118 was built near Hong Kong in Shenzhen. Imtech Marine presents a live & operational remote control room at the Europort exhibition, hall 1, stand 1124.

The remote support is extensive and comprises the VSAT network, the ICT network, PABX central telephone system and the total navigation, communication and entertainment package, including IPTV and satellite television. Additionally, VHF/UHF communications for the crane operators, a meteo and CCTV system, as well as a communications system for the helideck. Because the barges are often working offshore for many weeks at a time it is vital that any problems can be sorted out remotely. This agreement also includes ICT system management. For instance when there are crew changes and a new crew is boarding all necessary ICT actions are set up and prepared such as email accounts, file server changes, login passwords etc. Imtech Marine makes these changes remotely for Jack-Up Barge.

Frank Berends, Global Manager Remote Services : "Our aim is to eliminate all surprises with remote support, and thus reducing maintenance costs by remote monitoring. Imtech's GTAC (Global Technical Assistance Centre) provides all the resources for that, including three 24/7 Remote Control Rooms in Rotterdam, Houston and Singapore. Jack-Up Barge has given us the freedom and the trust to get the job done. Since we started to provide Remote monitoring & Maintenance for the JB-117 one and a half year ago, maintenance attendances to the Barge have been reduced substantially."

Continuity and crew welfare
Hugo Cramer, Technical Manager Jack-Up Barge comments: "The JB-117 is working on a three-year contract on a wind farm in the North Sea. With 24/7 support and remote monitoring, diagnostics and maintenance included, we are able to improve reliability of vital installations and reduce the maintenance costs by avoiding unplanned service calls. Monitoring the condition of the system remotely ensures us of continuity of operation. Jack-Up Barge also recognises that access to television and the Internet is very important for crew welfare. The crew works hard on long shifts and needs to be able to relax. Working with Imtech we know what to expect and that Imtech delivers." The two companies work in true partnership, he says.
Jack-Up Barge is one of the world's leading suppliers of Self Elevating Platforms for both the energy and heavy civil construction markets. Based in Sliedrecht, the Netherlands, Jack-Up Barge supplies two types of Self Elevating Platforms, the Modular and Monohull Jack-Up. JB-117 is in operation on building a windmill farm in the Nordsea above the German Bight. The first job for the JB-118 is to function as an accommodation platform in the North Sea for a period of four months. Because of this task, Imtech Marine received an expansion order for the network, telephone, entertainment and PA/GA system.

Petrobras, the operator for the BM-S-9 consortium, announces, together with its partners BG E&P Brasil and Repsol Sinopec Brasil, that the company's affiliate Guará BV has signed on its behalf a letter of intent to charter, through Modec Inc. and Schahin Petróleo e Gás S.A., an FPSO (floating production, storage and offloading unit) for use in production development of the pre-salt layer in the Carioca area, part of the Santos Basin's block BM-S-9.



The project provides for the initial connection of eight wells to the FPSO, four as producing wells and four for injection, with the possibility of subsequent additional wells. The Carioca area is expected to start producing in August 2016.



The platform will have a processing capacity of up to 100,000 barrels per day (bpd) of oil and 5 million m³/day of natural gas. The FPSO will be operated by the companies responsible for its construction and chartered to the BM-S-9 Consortium for a period of 20 years. The Carioca FPSO is scheduled to be delivered by June 2016.



The BM-S-9 Consortium is a partnership between Petrobras (the operator, with a 45% stake), BG E&P Brasil Ltda. (30%) and Repsol Sinopec Brasil S.A. (25%).

Technip was awarded by Qatar Petroleum an engineering, procurement, installation and commissioning contract for a strategically important* Offshore Project comprising a living quarter platform and an utility platform, with a bridge connecting the two platforms. The project location is within QP offshore facilities.

Technip will be responsible for the execution of the entire Project. The topsides for both platforms will be installed using the floatover technology, which Technip pioneered. This installation method enables large integrated topsides to be installed, thereby minimizing offshore hook-up and commissioning, without the use of large crane vessels.
Technip's operating center in Abu Dhabi, United Arab Emirates, with the support from the Group's operating centers in Paris, France and Doha, Qatar will execute the project.

Vaseem Khan, Senior Vice President of Technip in the Middle East, declared: "This contract reflects the growing interest for the floatover technology, by allowing a safe project execution in a time and cost-effective way while overcoming heavy-lift challenges. With this strategic project, we have the opportunity to further consolidate our presence in Qatar and to strengthen our relationship with Qatar Petroleum. It will also help us establish Technip as a leading Company in the region for executing offshore living quarter platform projects."

* For Technip, an "important" offshore contract is ranging from €100 to €250 million.

The Bureau of Ocean Energy Management (BOEM) has announced that the public comment period on the recently released Call for Information and Nominations on Proposed Chukchi Sea Oil and Gas Sale 237 will be extended to Dec. 3, 2013.

On Sept. 26, 2013, when the bureau published the Call, the public comment period was scheduled to last from Sept. 26 to Nov. 18. However, in light of the federal government shutdown from Oct. 1 through Oct. 16, BOEM is extending the comment period to ensure its partner agencies, industry and the public have adequate time to review the issues and comment.

An early step in the offshore oil and gas planning process, the Call does not indicate a final decision about any areas in the Chukchi Sea that may be offered for oil and gas leasing in the future.

The Call is designed to provide BOEM with information about interest in offshore oil and gas leasing by requesting that industry identify specific blocks in the Chukchi Sea Program Area, located in the Arctic off Alaska's northwest coast, that appear promising for oil and gas exploration and development.

The Call also asks all interested parties for comments and information relevant to BOEM's analysis of areas for potential leasing, including geological conditions such as bottom hazards; archaeological sites on the seabed or nearshore; multiple uses of the area, including navigation and subsistence; and other socioeconomic, biological or environmental information.

The Sept. 26 news release announcing the original Call can be found here: http://www.boem.gov/press09262013/

The Federal Register Notice is available at: https://federalregister.gov/a/2013-24053

Statoil recommends building a new drilling and processing platform on the Snorre field in the North Sea to extract maximum remaining reserves.

Together with Petoro and the other license partners, Statoil has worked hard to find a good solution for extending the life of the field to 2040.
A thorough evaluation of the "Snorre 2040" project has been carried out with detailed examination of two development concepts—a subsea development with continued use of the Snorre A and B platforms, or a development with a new platform tied in to Snorre A and B. 

"The platform solution is the best alternative for maximizing production and creating the greatest possible value," says Øystein Michelsen, Statoil executive vice president for the Norwegian shelf.

"Snorre 2040 is an important improved oil recovery (IOR) project and supports our ambition of achieving an average oil recovery rate of 60% from our fields on the Norwegian shelf."

Statoil is a world leader within IOR, with an average oil recovery rate of 50% from the Norwegian shelf.

Snorre field reserves are currently estimated at 1.55 billion barrels of oil. The original estimate when the plan for development and operation (PDO) was submitted in 1989 was about 760 million barrels of oil. Thanks to a number of IOR measures and use of new technology, recoverable reserves have more than doubled.

An important contribution to the increase in recoverable reserves came with the decision to install a second platform, Snorre B, on the northern part of the field, and to start reinjection of produced gas from the mid-1990s.

When the PDO was submitted, the estimated recovery rate was 25%. Today the estimated recovery rate is 47%, but Snorre has an ambition of implementing additional IOR measures that will enable the field to increase the recovery rate to 55%.

Øystein Michelsen emphasizes that more time will be needed to mature the development solution and make the decision basis more robust.
"Snorre 2040 is a huge project with significant investments, but it will also yield substantial value. Thorough preliminary work is important to arrive at the best possible solution. We are also seeing marked rising costs in our industry and we must ensure that value creation is optimal," says Michelsen.

"The change in the petroleum tax rules that was adopted in May also undermines the financial conditions of Snorre 2040, which means that we have to spend more time on maturing the project," says the executive vice president.

The final development concept decision is scheduled for the first quarter of 2015.

A new drilling and processing platform will also facilitate tie-in of new discoveries in the area. These are resources that might otherwise have ended up being not profitable to recover.

The partners in the Snorre license are Statoil (33.27556%), Petoro (30.0%), ExxonMobil E&P Norway (17.44596%), Idemitsu Petroleum Norge (9.6%), RWE Dea Norge (8.57108%) and Core Energy (1.1074%).

Exploration acquisition adds to opportunities in Australia

Chevron Corporation (NYSE:CVX) announced on Tuesday, that its Australian subsidiary has acquired exploration interests in two offshore blocks located in the Bight Basin, a deepwater frontier basin.

Blocks S12-2 and S12-3 in the Bight Basin are similar in size to the Gulf of Mexico and contain significant exploration potential.

Blocks S12-2 and S12-3, which span more than 8 million acres (32,375 square kilometers), are located approximately 275 miles (443 kilometers) west of Port Lincoln off the South Australia coast. Chevron Australia is the operator with a 100 percent interest.

Melody Meyer, president of Chevron Asia Pacific Exploration and Production Company, said, "The acquisition of blocks S12-2 and S12-3 demonstrates Chevron's continued focus on pursuing high-impact exploration opportunities to expand its resource base and reinforces the importance of Australia to Chevron's global growth strategy."

Chevron Australia Managing Director Roy Krzywosinski added, "We are extremely pleased to be awarded the S12-2 and S12-3 offshore blocks located in the Bight Basin. The Bight Basin is similar in size to the Gulf of Mexico, and these two blocks contain significant exploration potential."

Baker Hughes Incorporated (NYSE: BHI) has announced that PETRONAS Carigali Sdn. Bhd. (PCSB) has entered into a long-term Oilfield Service Agreement (OFSA) with Baker Hughes to enhance the recoverable reserves and production of hydrocarbons in the Greater D18 fields, offshore Malaysia.

The 23-year agreement is the result of a collaborative, 2 1/2-year field development study, leveraging Baker Hughes' reservoir evaluation capabilities to analyze the geology and reservoir attributes of the mature and compartmentalized D18 field. Challenged with production declines, Baker Hughes successfully deployed two integrated production enhancement programs to revitalize production in target wells. Through further analysis, technical experts developed a comprehensive field development plan with fit-for-purpose technology solutions.

"We have utilized our best people to come up with solutions which are going to help PETRONAS Carigali Sdn. Bhd. [PCSB] achieve their goals of increased oil recovery from mature fields. The partnership between PCSB and Baker Hughes on this project represents a significant milestone in expanding our offering with reservoir development in addition to our traditional products and services portfolio," says Zvonimir Djerfi, President of Asia Pacific Region for Baker Hughes.

With the challenges surrounding this marginal, complex reservoir, Baker Hughes' field management strategy combines technical expertise and integrated solutions to enhance existing production by identifying new targets and efficiently constructing new wells to maximize production throughout the entire life cycle of the field.

Baker Hughes will participate in the redevelopment cost for the Greater D18 field in return for remuneration from the incremental production. The collaborative arrangement will extend the life of Greater D18 and will help sustain the area's economic strength. The company has successfully implemented a similar modeling strategy in other areas, including Asia Pacific, Mexico and the United States.

Noble Energy, Inc. (NYSE: NBL) has announced results from the Paraiso-1 exploration well, located in the Tyra Bank concession area offshore Nicaragua. The well, which had hydrocarbon shows and found high-quality Tertiary-age carbonate reservoirs, did not encounter an accumulation of hydrocarbons. Located in a water depth of 1,220 feet, the well was drilled to a total depth of 10,415 feet.

Mike Putnam, Vice President, Exploration and Geoscience, commented, "Paraiso-1 was the first deepwater well drilled offshore Nicaragua and tested a new frontier exploration concept for this region. While we are disappointed that the well did not lead to a discovery, there were several positive observations during drilling. The information gathered from this well will be integrated into our regional geologic model to help us assess the remaining exploration potential over our nearly two million acre position offshore Nicaragua."

Following completion of permanent plugging and abandonment operations at the Paraiso-1 location, the drilling rig will be released. Noble Energy is operator of the well with a 70 percent working interest, subject to final government approvals for the assignment of the remaining interest to other parties.

Noble Energy's total company fourth quarter 2013 exploration expense is estimated to range from $225 to $265 million, including seismic acquisition and processing, unsuccessful well costs, and other geologic and geophysical expenditures. The fourth quarter exploration expense range indicates full year exploration expense to be around the lower end of the Company's original guidance range.

Nine production platforms will be completed this year, three 
of them are already on stream

Petrobras will receive nine production units in a single year for the first time ever. The installed production capacity of the platforms amounts to 1 million barrels per day and the units coming on stream will be essential for the company to double its current production and achieve the target of 4.2 million barrels of oil per day for 2020. The information was highlighted by the Company's president, Maria das Graças Silva Foster, during a lunch-lecture at the Offshore Technology Conference (OTC Brazil 2013) in Rio de Janeiro.

Of the nine units starting production this year, the President pointed out that the FPSOs Cidade de São Paulo, Cidade de Itajaí and Cidade de Paraty had already come on stream. Another two units - the FPSO P-63 and P-55 - are already in place and the P-58 should leave the Rio Grande ship yard going towards Parque das Baleias later this month. Besides these, the P-61, the TAD (Tender Assisted Drilling) which was built in China, and the P-62 will arrive at their final locations in December, the President said on Tuesday afternoon (October 29), in the session called "Planning and Management of Offshore Opportunities in Brazil: the Petrobras Perspective". "In five or six years time, The "P" for production will be more important for us than the "E" for exploration", the President said, comparing the effort and investment used to increase the Oil Company's production with exploration activities aimed at new discoveries.

The President also highlighted the growth of the shipbuilding industry in recent years. "We are very proud of the shipyards in Brazil. 10 years ago, a lot of people laughed when we mentioned local content", she said. "In addition to the 17 stationary production units that are currently under construction in Brazil, we have 28 rigs and 41 transport ships being built in Brazil. To meet this (production) curve, we have 12 more contracts to do", said the executive. For her, one of the reasons for the success of the Brazilian shipyards is the association with experienced foreign companies, a criterion that has become a Petrobras demand to sign contracts.

Exploration success in the pre-salt is "spectacular", the President said

The President celebrated the success of pre-salt exploration, which reached 100% in 2013. She revealed that 13 wells have been drilled in the pre-salt this year, and the Company has found oil in all of them, which the executive rated as "spectacular". Altogether, 144 exploratory wells have been drilled in the pre-salt attaining an 82% success rate. "Our exploration success is impressive. If we count offshore and onshore wells, we have a 65% rate, which is far higher than the global average", she compared. She pointed out that Brazil accounted for 62% of large deepwater discoveries world-wide between 2007 and 2012.

On the newly auctioned Libra area, in which Petrobras has a 40% stake, the President expects the first oil to be extracted in 2020. "The regulatory framework (production sharing) is clear, objective and unambiguous", she said, noting that in 2017, when investments in Libra will be more significant, Petrobras will be producing 750,000 barrels per day more than the current 2 million barrels of oil produced daily today, which will increase the Company's cash.

Graça Foster also highlighted the importance of partnerships with Brazilian universities and research institutes around the world: "We have spectacular universities in Brazil, we have an intelligence network and we have invested heavily in technology in Brazil". Finally, she talked about the importance of investing in professional training, mainly in the middle level, such as technicians, supervisors and workshop masters: "Middle level training is a major bottleneck", she said.

A consortium of companies, including Royal Dutch Shell plc ("Shell"), Petrobras, Total, CNPC and CNOOC have won a 35-year production sharing contract to develop the giant Libra pre-salt oil discovery located in the Santos Basin, offshore Brazil.

The Brazilian regulator, Agência Nacional do Petróleo (ANP), estimates Libra's recoverable resources of between 8 to 12 billion barrels of oil.

"The Libra oil discovery in Brazil is one of the largest deep water oil accumulations in the world. We look forward to applying Shell's global deep water experience and technology, to support the profitable development of this exciting opportunity," said Peter Voser, Chief Executive Officer, Royal Dutch Shell.
Shell holds 20% in the consortium, with Petrobras 40% as operator, Total 20%, CNPC 10% and CNOOC 10%. The consortium will work together in an integrated fashion to support Petrobras, the most experienced operator in the Brazilian pre-salt, and will incorporate each company's deep water skills, people and technology for the success of the venture.

The production sharing contract is expected to be signed in November 2013. As part of the winning bid, Shell will pay its 20-percent share of the total signing bonus of USD $1.4 billion [3.0 billion reais], and fulfill the minimum work program no later than end 2017.
The ultra-deep water Libra accumulation is located in Santos Basin, approximately 170 kilometers (105 miles) off the coast of Rio de Janeiro. The block covers approximately 1,550 square kilometers in water depths of around 2,000 meters (6,500 feet). The reservoir depth is around 3,500 meters below the sea floor (11,500 feet). The ANP estimates that total gross peak oil production could reach 1.4 million barrels per day. Further appraisal is required to firm up this estimate, the development concept and a first oil date.

Shell is one of the industry's pioneers in deep water oil and gas with some 330,000 boe/d of production, world-wide, from deep water in 2012. Our commitment to technology and innovation continues to be at the core of our strategy. As energy projects become more complex and more technically demanding, we believe our engineering expertise will be a deciding factor in the growth of our businesses.

Shell was the first International Oil Company to produce on a commercial scale in Brazil and has more than 100 years of history within the country, with circa 65,000 boe/d of operated production in 2012. Shell is currently operating two Floating, Production, Storage and Offloading (FPSO) vessels in Brazil's offshore – the Espírito Santo at Parque das Conchas and the Fluminense at the Bijupirá/Salema fields - and has recently announced projects to expand production at both fields.
Shell also operates and owns an 80% interest in the BM-S-54 block, where the Gato do Mato discovery is being appraised. Shell has also other interests in Brazil, particularly our Lubricants business and our joint venture Raízen, the leading sugar cane ethanol producer and fuels retailer.

As fast-growing energy use in Southeast Asia leads to a sharp rise in the region’s dependence on oil imports and a reduction in its surplus of natural gas and coal for export, the International Energy Agency (IEA) has urged countries in the region to take serious action to improve energy efficiency.

“Southeast Asia is, along with China and India, shifting the center of gravity of the global energy system to Asia,” IEA Executive Director Maria van der Hoeven said at the launch of a World Energy Outlook Special Report, Southeast Asia Energy Outlook, which provides a comprehensive picture of the region’s energy future. Joining Ms. Van der Hoeven at the launch in Bangkok were Thai Minister of Energy H.E. Pongsak Ruktapongpisal and Hidetoshi Nishimura, Executive Director of the Economic Research Institute for ASEAN and East Asia.

The report projects Southeast Asia’s energy demand to increase by more than 80% in the period to 2035, a rise equivalent to current demand in Japan. Currently the region’s per-capita energy use is still very low, in part because 134 million people, or over one-fifth of the population, lack access to electricity.

Increasing reliance on oil imports will impose high costs on Southeast Asian economies and leave them more vulnerable to potential disruptions. The report projects that by 2035, the region’s oil imports will rise to just over 5 million barrels per day, making it the world’s fourth-largest oil importer after China, India and the European Union and doubling its dependency (to 75% of demand). Southeast Asia’s annual spending on oil imports is seen rising to $240 billion in 2035, equivalent to almost 4% of its GDP. Thailand’s and Indonesia’s oil import bills are projected to be the highest in the region, tripling to nearly $70 billion each in 2035.

According to the report, Southeast Asia will see a reduction in the surplus of natural gas and coal for export, as production is increasingly diverted to domestic markets. Its net gas exports are cut by more than three-quarters to 14 billion cubic meters in 2035. The region’s net coal exports also decline after 2020 as regional demand surges and demand in the wider Asia-Pacific market slackens. Indonesia’s coal production rises by almost 90% as it remains, by a very large margin, the world’s top exporter of steam coal.

The WEO Special Report highlights that the power sector is fundamental to the energy outlook for Southeast Asia, and that within it, coal is emerging as the fuel of choice because of its relative abundance and affordability in the region. Electricity generation is projected to increase by more than the current power output of India, with coal accounting for almost 60% of the growth. “The rising share of coal in power generation underscores the urgent need to deploy more efficient coal-fired power plants,” Ms. Van der Hoeven said. Currently the average efficiency of these facilities is very low, at just 34%, owing to the almost exclusive use of subcritical technologies.

Developing policies to attract investment is vital for enhancing energy security, affordability and sustainability in Southeast Asia. Around $1.7 trillion of investment in energy-supply infrastructure is required in the period to 2035. The report notes underdeveloped energy transport networks, the need for greater stability and consistency in the application of energy-related policies and subsidized energy prices as key challenges that must be overcome to mobilize this level of investment. The IEA noted the detrimental effects that fossil fuel subsidies have on energy markets, finding that in Southeast Asia they amounted to $51 billion in 2012.

The report includes an Efficient ASEAN Scenario that highlights the gains possible in Southeast Asia simply by adopting energy efficiency measures that make economic sense. Doing so would cut projected energy demand by almost 15% in 2035, an amount that exceeds Thailand’s current energy demand. Net oil imports would fall by around 700 kb/d, comparable with Malaysia’s current production. And regional GDP would rise by about 2% in 2035, as reduced spending on energy increases disposable income and stimulates economic activity.

To download the Southeast Asia Energy Outlook, please click here.

To see the slides presented at the report’s launch, please click here

Transocean Ltd. (NYSE: RIG) (SIX: RIGN) announces it has been awarded a five-year contract for a newbuild dynamically positioned ultra-deepwater drillship by Chevron U.S.A. Inc. Shipyard delivery is scheduled for the second quarter of 2016. After customer acceptance, the contract is expected to commence in the fourth quarter of 2016, contributing an estimated revenue backlog of approximately $1.1 billion, excluding mobilization. Excluding capitalized interest, the capital investment for the newbuild drillship is an estimated $725 million. Capital costs include the shipyard contract; project management; all owner-furnished equipment; capital spares and inventory; and all costs associated with operational readiness.

Featuring state-of-the-art equipment, the newbuild drillship will include Transocean's patented dual-activity drilling technology that allows for parallel drilling operations. The vessel will be outfitted with two 15,000 psi blowout preventers (BOPs) which are expected to reduce non-productive time between wells. The drillship will be able to accommodate a future upgrade to a 20,000 psi BOP when it becomes available from the OEM suppliers. The rig will also feature an industry-leading 2.5-million-pound hook load capacity, a variable deckload capacity of 23,000 metric tons, enhanced well-completion capabilities and diesel engines configured to comply with anticipated Tier III International Maritime Organization (IMO) emissions standards. The drillship is designed and outfitted to operate in water depths of up to 12,000 feet and drill wells to 40,000 feet. In addition, the drillship will have accommodations for 240 people.

Construction of the newbuild drillship is expected to commence during the fourth quarter of 2014 at the Daewoo Shipbuilding and Marine Engineering Co., Ltd. facility in Okpo, South Korea, where Transocean's five Enhanced Enterprise-Class rigs were built and where the company currently has six other ultra-deepwater drillships under construction.
"We are delighted to continue our partnership with Chevron in pioneering ultra-deepwater drillships that in the past have set world records and achieved strong utilization with time-saving efficiencies," said Steven L. Newman, President and Chief Executive Officer of Transocean Ltd. "Further, the addition of this latest newbuild drillship demonstrates the execution of our asset strategy and commitment to increasing our exposure to high-specification floaters with industry-leading capabilities."

As Brazil works to extract its vast offshore oil and gas reserves found in pre-salt formations, one of the most challenging locations is the Santos Basin, where operators face a number of complex production and transportation conditions.  (NYSE: GE) has introduced innovative flexible pipes to help customers overcome these challenges by developing new materials for the pipes required to bring hydrocarbons to the surface.

During the past three years, the GE Oil & Gas team in Niterói has developed new flexible pipe technologies to meet the specific conditions of the Santos Basin oil. As a result, the company now is one of only two accredited providers of advanced flexible pipes to be used in this location.

GE's new flexible pipes feature important advances as each pipe layer is made with a specific material to ensure the safe and reliable transportation of oil and natural gas in the Santos Basin. Traditional flexible pipes are already highly engineered technologies that must be able to handle extreme pressures, temperatures and currents. The new pipes developed for the Santos Basin build on these characteristics by adding new materials specifically engineered to withstand the more acidic environment. Altogether, about 70 professionals worked on the flexible pipe technology project, which the GE team is continuing to enhance through more research and development.

GE's latest flexible pipe innovations build on the company's 2011 acquisition of Wellstream Holdings, which enabled GE Oil & Gas to further grow in the floating production, storage and offloading offshore segment that underpins deepwater oil and gas production activities in Brazil and around the world. The business specializes in the engineering and manufacturing of high-quality flexible risers and flowline products for oil and gas transportation in the subsea production industry.

To drive additional innovation, GE is establishing a new $250 million Global Research Center in Rio de Janeiro, which will host a subsea systems laboratory that will focus on developing more solutions for the pre-salt layer and ultra-deep water exploration.

Brazil is a key growth market for GE Oil & Gas, with the country expecting investments to reach about $320 billion by 2021, according to Energy Research Company. In addition to the future subsea systems laboratory, the company also has announced a total of $262 million in investments to expand its equipment production facilities in Niterói and Macaé—both in Rio de Janeiro—and Jandira in São Paulo.

As the economic fallout from the recent terrorist attack on Kenya's Westgate Mall by Somali militants is still unfolding, the country's petroleum industry will have to focus its attention toward security in order to keep its momentum, says an analyst with research and consulting firm GlobalData.

John McCormack, GlobalData's Lead Analyst covering Sub Saharan Africa, believes that while the Somali extremist group Al-Shabaab has not made a specific threat, Kenya's petroleum industry is of strategic importance to the country's economic future and is itself a feasible target for future attacks.

Although the attack on the Westgate Mall is likely to have a minimal impact on the overall pace of Kenya's oil and gas operations, most International Oil Companies (IOCs) will have to invest in security, especially with the relocation of high numbers of expatriates to Kenya. Additionally, there will also be a heightened risk of damage to oil and gas infrastructure, such as pipelines. These are particularly difficult to secure from Somali militants, McCormack says.

GlobalData forecasts the first oil production in Kenya to be achieved in 2016, from blocks 10BB/13T, once oil and gas legislative measures and infrastructure have been put in place. The Kenyan government is expected to receive revenues of $300m per year from oil produced from these blocks alone over the next 30 years.

According to McCormack, Kenya doesn'thave a safety and security master plan in place to protect its oil and gas infrastructure. However, Kenya Petroleum Refinery Company (KPRC) did tighten security around its Mombasa refinery facility, the only one in East Africa, following the attack.

Additionally, both security personnel and unarmed security guards are deployed at all onshore and offshore blocks where exploration operations are ongoing.
Furthermore, drilling rigs, especially those located close to the border of Kenya and Somalia in the Mandera, Anza and Lamu basins, are now on alert for militants after the Kenyan government showed no willingness to accede to the demands of Al-Shabaab.

The Kenyan government may lose some of its contract negotiating powers with the IOCs as a result of the deteriorating security conditions in the country. However, although the Westgate Mall attack will cause investors to consider the future ramifications of terrorism in Kenya, the opportunity-cost of turning down investment in the country is likely too high to justify not pushing forward, McCormack concludes.

Comment provided by John McCormack, GlobalData's Lead Analyst covering Sub Saharan Africa. John Sisa and Jamie Inkster, GlobalData's Analysts covering Oil & Gas, also contributed to this analysis.

Construction of the Keystone Gulf Coast Pipeline (KGCP) has advanced considerably, according to Genscape’s most recent flyovers on September 29^th and October 6^th. Genscape uses proprietary monitoring technology and aerial photography to monitor market moving pipeline flow disruptions and infrastructure projects to offer market participants a real-time look at the factors driving the U.S. and Canadian oil markets.

On October 2^nd TransCanada stated that major construction would be complete by the end of October and that the pipe would be ready for line filling shortly thereafter. Genscape is now monitoring power consumption at the Lufkin and Delta pumping stations and will be able to detect the power consumption to these pumping stations indicative of line fill activity. Delta is not expected to be necessary for the initial start-up capacity. Genscape’s analysts’ believe that late December to early January is a realistic estimate for the completion of the line fill, based on acceleration in construction progress from last month's flight. The bulk of work remaining on the project is centered on the origin Cushing pumping station.

At the Cushing terminal, all seven newly constructed tanks have hydrotested. Mixer installation appears complete, while tank pipeline connections require further work. Genscape believes that the associated connections are not necessary for initial KGCP fill, and that the tanks could potentially be bypassed. The terminal will have 2.25mn bbls of storage capacity.

Additionally, exposed pipe was observed near the Tupelo and Bryan facilities and crews were observed working on pipeline connectivity along the ROW at the Tupelo pumping station. The Cromwell, Bryan, Winnsboro, Lufkin and Liberty pumping stations each have four pumps installed. Hydrostatic testing looks to be complete at all pumping facilities except for the Bryan pumping station. After successful hydrostatic testing, final grading would take place at each pumping facility followed by the installation of a security fence, according to a TransCanada document. The Bryan pumping facility did not have a security fence installed as of Gencscape’s latest flight. The Tupelo, Delta, Lake Tyler and Corrigan stations do not have pumps installed at this time. Genscape believes these stations do not need pumps for the line to flow at its initial stated capacity of 700,000 bpd.

The 36-inch-diameter KGCP will flow 485 miles from Cushing, OK, to Nederland, TX. The line will have an initial capacity of 700,000 bpd with the option to expand to 830,000 bpd. Line fill for KGCP is approximately 3.2mn bbls. Genscape estimates it will take approximately 40-60 days to fill the line at near 54-81,000 bpd fill rate. The Keystone pipeline from Hardisty, AB, to Patoka, IL, took nearly 180 days to fill in 2010 at near 50,000 bpd fill rate. Line fill for Keystone to Patoka was approximately 9.2mn bbls. TransCanada estimated the line fill duration would be approximately 30 days. Sunoco Logistics Partners LP’s Nederland terminal will be the initial terminus of the KGCP pipeline, according to a Reuters report. Valero’s Lucas storage terminal would also receive crude from the line in Q1 2014 according to a September SEC filing.

TransCanada stated construction on the Houston lateral was slated to begin Q4 2013 and is estimated to be in service by Q4 2014. The lateral will be approximately 48 miles from the Liberty pumping station to Houston’s refining center. Click here to view the aerial photos that supplement this report.

Genscape’s Mid-Continent Pipeline clients receive ongoing notices of pipeline flows and infrastructure projects in advance of market reports. A free trial of the Mid-Continent Pipeline service, and all Genscape’s oil market services, is available by visiting info.genscape.com/keystone-october.