During Offshore Europe, a panel of leading international industry experts will discuss the preconceived perceptions that students and graduates have of a career in oil and gas, and how they differ from the experiences of those operating in the sector.
Hosted by the Society of Petroleum Engineers (SPE) Aberdeen Section’s Young Professional Committee, the panel will take place during the final day of Offshore Europe, Friday 11 September, at the Aberdeen Exhibition and Conference Centre and aims to inspire the next generation to pursue a career in the oil and gas sector, whilst also motivating young professionals to consider new opportunities within the industry.
SPE President and director general of Statoil Mexico, Helge Hove Haldorsen, will lead the panel discussion. Joining him will be David White, senior technology adviser at Schlumberger, Rod Christie, CEO of subsea systems and drilling at GE Oil & Gas, Shona Cormack, vice-principal and pro-vice chancellor of Robert Gordon University, and Bob Greenwood, partner and head of oil and gas practice at Odgers Berndtson.
Shankar Bhukya, SPE Aberdeen Chairman, said: “The ever-changing nature of the oil and gas industry has been particularly palpable of late and it is important, more now than ever, that leading professionals come together to share with today’s students and graduates their experiences of the industry and the vast opportunities available.
“With continuous technological advancement and fields including enhanced oil recovery and decommissioning growing in importance each day, particularly in the UKCS, talented individuals are in high demand and there are still excellent career prospects out there for them. At SPE Aberdeen, we continue to look at new ways to engage and enthuse the next generation and this event represents a fantastic platform upon which to demonstrate the potential a career in oil and gas can offer.
“The pre-event online poll, as well as the question and answer section of the panel discussion offers delegates the chance to voice their opinions and have their concerns addressed by leading professionals who have already made their mark on the industry. Together, we can convey the message that the oil and gas industry is still thriving and should not be disregarded by the new generation. ”
SPE Aberdeen has developed an online poll to gather the opinions of students, graduates and young professionals. The results will be presented during the seminar and will form part of the discussion. If you would like to complete the poll please visit - https://www.surveymonkey.com/s/W99XVSB.
After just four years in production, the Peregrino field in the Campos basin offshore Brazil has passed a significant milestone, with 100 million barrels of oil produced since April 2011.
The Peregrino field includes two fixed drilling platforms (WHP A and WHP B), and the floating production and storage unit FPSO Peregrino.
The field, jointly owned by Statoil and Chinese Sinochem, achieved the milestone on August 2.
"We are pleased to have reached a major milestone in our Peregrino operations,” says Pål Eitrheim, country manager of Statoil Brazil.
“Peregrino demonstrates the power of possible, and we are proud to operate a project that is both exciting and challenging. These results reflect the professionalism of our people, and the application of technology developed by Statoil, in Brazil and elsewhere. We are constantly learning and we look forward to reaching new milestones as we continue to develop this large field”, he says.
According to a report published by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels (ANP) in March 2015, Peregrino is Brazil's eighth largest field, and has the second heaviest oil ever produced in Brazil.
It is also the largest field operated by Statoil outside Norway and accounts for about 12% of its international production (around 720 thousand barrels per day).
The operation includes two fixed drilling platforms (WHP A and WHP B), and a floating production and storage unit (FPSO Peregrino), with a production capacity of 100,000 barrels per day. Statoil holds a 60% stake and is the operator of the field, while Sinochem holds the remaining 40%. With an excellent track record, Peregrino has achieved all production, efficiency, cost and safety targets in 2014.
In January this year, the development plan of Peregrino Phase II was submitted to ANP. With total estimated investments of USD 3.5 billion, the project involves a new drilling platform (WHP C) and will add about 250 million barrels in recoverable reserves to the Peregrino field. Phase II of the project will enable the extension of the economic life of Peregrino and is an important and strategic part of Statoil’s ambition to consolidate a strong position in Brazil.
Technip has been awarded an engineering, procurement, construction, installation and commissioning contract by PETRONAS Carigali for the tie-in of PETRONAS first Floating Liquefied Natural Gas (PFLNG1) facility to KAKG-A platform in Kanowit field, located 200 kilometers offshore Bintulu, East Malaysia, at a water depth of approximately 80 meters.
The contract covers the procurement and installation of a 3.2 kilometers flexible flowline between the existing KAKG-A central processing platform in Kanowit field to the PFLNG1 riser. It also includes modification and tie-in works at KAKG-A.
Technip’s operating center in Kuala Lumpur, Malaysia, will execute the contract. The Group will leverage its unique integrated approach in the subsea business. The flexible flowline will be manufactured in Asiaflex Products, Technip’s manufacturing facility in Tanjung Langsat, Johor, Malaysia. It will then be installed by the Group’s multipurpose vessel, the Deep Orient. The installation campaign is scheduled for completion in late 2015.
KK Lim, President of Technip in Asia Pacific, commented, "With this award, we are able to offer to PETRONAS a competitive solution through our unique vertically integrated value chain for subsea infrastructures, from the design and manufacture of the flexible pipes up to its installation, using Technip assets”.
The PFLNG1 vessel, which will produce 1.2 million tons of LNG per year, will play a significant role in PETRONAS’ efforts to unlock gas reserves in Malaysia's remote and stranded fields to help meet the growing demand for gas.
Technip is a FLNG leader with first mover advantage having secured the two world’s first FLNG projects including PETRONAS FLNG1, thanks to its unique combination of know-how and technologies in subsea, offshore and onshore.
InterMoor Inc., an Acteon company, has completed its role in the largest foundation installation project offshore Trinidad and Tobago to date. The final stage of the project involved hooking up Diamond Offshore Drilling Inc.’s Ocean Victory semisubmersible drilling rig to the preset mooring spread InterMoor had previously installed. This step marks the completion of InterMoor’s mooring and foundation installation campaign for BP Trinidad and Tobago’s (bpTT) Juniper gas project.
The hookup took less than four days and required 14 InterMoor personnel offshore, including rig coordinators and superintendents, riggers and engineers aboard the UOS Pathfinder anchor-handling vessel.
Tom Fulton, global president, InterMoor, said, “Our engineering, fabrication and operations teams all worked well together and each played important roles in the successful completion of this project. InterMoor is dedicating more and more resources to maintain an active presence and excellent service to our clients in this part of the world.”
Before the hookup, InterMoor successfully completed a contract with bpTT, which included the initial design of a mooring system, the fabrication of driven piles and the installation of a preset mooring spread. InterMoor designed and fabricated eight piles (1.2 m in diameter by 39 m long) at its facility in Morgan City, USA, and provided offshore project management services for the mooring preset campaign. This included installing the driven piles using H-links and 300 m of ground chain per leg from the Boa Deep C construction vessel. The Juniper project was carried out in a water depth of 100 m with strong water currents.
The mooring solution engineering began in 2011 and offshore installation was completed in early November 2014. The hookup was completed in May 2015.
InterMoor is the only mooring service company worldwide that offers full services for both temporary and permanent moorings.
A new Wood Mackenzie study commissioned by the American Petroleum Institute finds that pro-development regulations for oil and natural gas development in the United States could dramatically improve the nation’s economic prospects for the foreseeable future. The study contends that nationally, by 2035, pro energy policies could yield an additional:
What could these findings mean to Florida? In the blog post included below, online on API’s blog “EnergyTomorrow.org,” we explore the oil and natural gas industry’s intrinsic value to Florida and detail how allowing crude oil exports can bode well for Floridians.
Energizing Florida
Our series highlighting the economic and jobs impact of energy in each of the 50 states continues today with Florida. We started our focus on the state level with Virginia on June 29. All information covered in this series can be found online here, arranged on an interactive map of the United States. State-specific information across the country will be populated on this map as the series continues.
As we can see with Florida, the energy impacts of the states individually combine to form energy’s national economic and jobs picture: 9.8 million jobs supported and $1.2 trillion in value added.
Click here to bring up a two-page snapshot of energy’s benefits to Florida.
The top-line numbers for Florida: more than 286,000 jobs supported statewide, according to a PwC study issued in 2013; over $23 billion added to the state economy; $13 billion contributed to the state’s labor income.
Page 2 of the document highlights the promising economic opportunities for Floridians if crude oil exports are allowed. If federal restrictions on U.S. crude exports are lifted Florida could add up to 10,736 jobs and more than one billion dollars to the state economy in 2020.
We’ve now seen reports -- from Columbia University, IHS, ICF, Brookings, the Aspen Institute, the Government Accountability Office, the Congressional Budget Office, the Energy Information Administration (EIA) and others – all pointing to the same conclusions: Blocking trade in crude oil harms consumers, it harms the economy, and it undermines America’s role as a global leader.
Crude oil exports would put downward pressure on crude on U.S. gasoline prices. U.S. weighted average petroleum product prices are expected to decline as much as 2.3 cents per gallon 2015–2035 when U.S. crude exports are allowed. The greatest potential annual decline is 3.8 cents per gallon in 2017. These price decreases for gasoline, heating oil and diesel could save American consumers up to $5.8 billion per year, on average, over the 2015–2035 period.
When added up across all of the states that can benefit from exports, nationally, LNG and crude exports could significantly reduce our trade deficit, increase government revenues, grow the economy, and support millions of U.S. jobs in engineering, manufacturing, construction, and facility operations.
Energy is critically important to Florida, serving as a key engine for the state economy – expanding job opportunities and offering the hope of prosperity to individual Floridians and their families.
The future benefits of energy for Florida – and the rest of the country – largely depend on national decisions on the country’s energy path. A new Wood Mackenzie study contrasts the benefits that a set of pro-development policies could have on energy supplies, jobs, the economy and American households with the likely negative effects on energy of regulatory constrained policies. The key comparisons are found on the first page of the linked document.
Energy is essential for all facets of our daily lives, from powering national, state and local economies to powering the family vehicle. Safe, responsible development of domestic oil and natural gas resources is linked to individual prosperity, energy security and basic liberties.
Energy services company LR Senergy has been awarded a number of contracts worth a combined US$7 million in the Middle East, Europe and Asia as it continues to adapt to the difficult and changing market conditions.
Employers of thousands of marine crew are being urged to be prepared following changes to the Standards of Training, Certification and Watchkeeping (STCW) - or face potentially being unable to set sail.
The changes affect UK seafarers who hold basic STCW certification, or have six months or more sea service prior to 1 August 1998 and are deemed to be qualified in any of the following:
George Masson, Marine Team Leader at Petrofac Training Services’ (PTS) quayside facility in Aberdeen, explained: “The changes are being introduced to ensure seafarers maintain the necessary standards of competence to undertake practical emergency, occupational safety and survival functions such as launching life rafts or dealing with fires.”
As of 1 January 2017, seafarers must have completed the training course or updating training within the previous five years, followed by refresher training every five years.
While the requirements are being introduced globally, UK employers are expected to be amongst those most affected as updating training has already been standard practice in many regions. Seafarers who hold UK certification have been required to demonstrate their competence on an ongoing basis on board their vessel but are unlikely to have undertaken approved refresher training.
Crewing companies and owners or operators of all types of vessel will be affected, including supply ships, support vessels, ERRVs, FPSOs, drillships, ferries and flotels, amongst others.
George Masson added: “The new requirements will apply to thousands of seafarers, so we are encouraging companies to be ahead of the game and to plan their training schedules accordingly. The worst case scenario is that workers may not be able to sail and carry out their duties but this can be avoided.”
PTS is approved by the UK Maritime and Coastguard Agency (MCA) to deliver initial and updating training for all the required courses, and is also arranging an increasing number of courses to meet customer-specific requirements.
Maersk Drilling has been awarded a 5-year contract extension for the semi-submersible Heydar Aliyev rig with BP Exploration (Shah Deniz) Limited acting as Operator of the Shah Deniz field . The rig will continue working on the development of the Shah Deniz field in the Caspian Sea offshore Azerbaijan. The extension is in direct continuation of the current contract ending May 2016 and extends the contract until May 2021. The estimated value of the contract extension is up to USD 523m.
“We are very pleased with the extension for the Heydar Aliyev rig and look forward to continue our long standing cooperation with BP,” says Claus V. Hemmingsen, CEO in Maersk Drilling and member of the Executive Board in the Maersk Group, and continues: “With this contract we continue to build our contract backlog providing further revenue visibility. It is very encouraging that we continue to build backlog in this very challenging market.” The Heydar Aliyev rig (formerly known as Maersk Explorer) was delivered in 2003 and is designed for year-round operations at water depths from 40m to 1,000m (147ft to 3,280ft).
Subsea 7 S.A. (Oslo Børs: SUBC, ADR: SUBCY) has announced the award of a contract with a value of approximately USD 500 million by BP, and partner DEA, for the development of the Taurus and Libra subsea fields offshore Alexandria, Egypt. The contract is the first phase of Egypt's West Nile Delta project where field development will be at depths of approximately 800 meters.
Excelerate Receives Approval to Move Forward with the Construction and Operation of LNG Terminal
On July 24, 2015, the Federal Energy Regulatory Commission (FERC) issued its order granting authorization to Excelerate Energy ("Excelerate"), in cooperation with the Puerto Rico Electric Power Authority (PREPA), to site, construct, and operate the proposed Aguirre Offshore GasPort Project ("Project") located offshore Puerto Rico. The order confirms the final Environmental Impact Statement (EIS) that resulted in a finding of no significant environmental impact. As part of the order, the Project will comply with all the environmental conditions outlined by FERC.
"We are pleased to receive the order from FERC after nearly four years of extensive environmental review," stated Rob Bryngelson, Excelerate's chief executive officer. "During this time, Excelerate has not diminished its efforts to deliver the beneficial Aguirre Offshore project, nor has the company wavered in its support for PREPA's and the Government of Puerto Rico. Excelerate firmly believes that the Project will provide a valuable service to PREPA and bring tangible and enduring benefits to the citizens of Puerto Rico."
"The order represents an important milestone in the development of the project," stated PREPA's interim executive director, Carlos Castro. "This project is critical for PREPA to reduce the cost of energy in Puerto Rico and to reduce the emission of air pollutants."
The proposed project will be a floating liquefied natural gas (LNG) terminal with the same capabilities as a land-based terminal. The terminal will consist of a floating storage and regasification unit (FSRU), minimal infrastructure to moor the vessel, and a subsea pipeline to deliver the gas onshore. The facility will provide fuel to PREPA's Central Aguirre Power Complex. Fuel cost reduction and environmental improvements, such as improved air quality and reduced barge traffic in the environmentally sensitive Jobos Bay, are the primary drivers for bringing the Project to Puerto Rico.
The Project has undergone an exhaustive analysis through the environmental review process that began in December of 2011. Within this timeframe, Excelerate has provided extensive information regarding the design, construction and operation of the Project to the FERC, cooperating agencies, and the general public. Also, both Excelerate and PREPA have held numerous meetings with the private and public sectors, as well as local communities and interested parties, to ensure complete transparency throughout the entire permitting process. On February 20, 2015, the FERC issued the final EIS, which assessed the environmental impacts of the Project and determined that the Project was suitable for construction and operation.
In the coming months, Excelerate will continue to work with FERC and cooperating agencies in preparation for the commencement of construction. Construction is estimated to begin the first quarter of 2016, with an in-service date of the second quarter of 2017.
All project related information can be found on the Project website.
Operator Statoil and its PL146/PL333 partner Total E&P Norge have made a gas and condensate discovery in the Julius prospect in the King Lear area in the North Sea.
The discovery well 2/4-23S, drilled by Maersk Gallant, proved gas and condensate in the Ula formation. Statoil estimates the volumes in Julius to be between 15 and 75 million barrels of recoverable oil equivalent.
The well 2/4-23S aimed also to appraise the King Lear gas and condensate discovery made by the PL146/PL333 partnership in 2012.
The well provided important information on reservoir distribution and reservoir communication in the King Lear discovery. The acquired data will now be further analyzed.
It is expected that the King Lear volumes will stay within the previously communicated range of 70-200 million barrels of recoverable oil equivalent.
“The King Lear and Julius discoveries are located in one of the most mature parts of the Norwegian continental shelf - just 20 kilometers north of Ekofisk, the first commercial NCS discovery made 45 years ago. The discoveries confirm Statoil’s view that even such mature areas of the NCS still have an interesting exploration potential,” says May-Liss Hauknes, Statoil vice president for exploration in the North Sea.
“Since the King Lear discovery, the main focus of the license partnership has been to clarify the resource basis within PL146/PL333. Following the positive results of the Julius well, the partnership will start working on an optimal plan for a timely development of the discovered resources. The Julius discovery will be included in the resource base for a future PL146/PL333 development decision,” says Edward Prestholm, acting head of early phase field development on the NCS in Statoil.
Total has started production from Dalia Phase 1A, a new development on its deep offshore operated Block 17, located 135 km off the coast of Angola. Dalia Phase 1A will develop additional reserves of 51 million barrels (Mb) and will contribute 30,000 barrels per day (b/d) to the block’s production.
Image courtesy: Nigeria Energy Intelligence
“The Dalia FPSO came on stream nearly nine years ago and with the addition of Phase 1A will still produce around 200,000 b/d. It is the latest milestone in the success story of Block 17, Total’s most prolific license with cumulative production reaching two billion barrels in May 2015,” explained Arnaud Breuillac, President Exploration & Production. “Dalia Phase 1A demonstrates Total’s commitment to maximizing value through the optimal use of existing facilities. These types of profitable satellite tie-back developments play an important role in maintaining production levels and generating additional free cash flow for the Group.”
The Dalia Phase 1A project involves the drilling of seven infill wells tied back to the Dalia Floating Production Storage and Offloading (FPSO) unit.
Total Exploration & Production in Angola
Total celebrated its 60th anniversary in Angola in 2013. In 2014, the Group’s equity production reached 200,000 barrels of oil equivalent per day (boe/d), coming essentially from Blocks 17, 0 and 14. In early 2015, Total’s operated production exceeded 700,000 boe/d, making it the country’s leading oil operator.
Total operates Block 17 with a 40% interest alongside Statoil (23.33%), Esso Exploration Angola Block 17 Ltd (20%) and BP Exploration Angola Ltd (16.67%). Sonangol is the concessionaire of the license. The Group operates four FPSO units on the major production zones of the block: Girassol, Dalia, Pazflor and CLOV.
Total also operates with a 30% interest the ultra deep offshore Kaombo development located on Block 32. A final investment decision was made in April 2014 to develop Kaombo’s estimated reserves of 650 Mb via two converted FPSOs with a total production capacity of 230,000 b/d.
BG Group (LSE: BG.L), a world leader in exploration and LNG has announced first oil from the Cidade de Itaguaí floating, production, storage and offloading (FPSO) vessel, the sixth unit to start production across the Group's significant discoveries in the Santos Basin, offshore Brazil. The FPSO will produce from the Iracema North area of the Lula field in the Petrobras-operated BM-S-11 block.
Anchored 240 km off the coast of Rio de Janeiro, the Cidade de Itaguaí is approximately 2 220 meters above the ocean floor. This is the second leased FPSO deployed on the Iracema development and will double the gross production capacity to 300 thousand barrels of oil per day and 16 million cubic meters of natural gas per day from the area. The FPSO will also be able to store 1.6 million barrels of oil.
BG Group has a 25% interest in Block BM-S-11 (Petróleo Brasileiro S.A., operator, 65% and Petrogal Brasil S.A., 10%). BG Group also has a 30% interest in Block BM-S-9 (Petróleo Brasileiro S.A., operator, 45% and Repsol Sinopec Brasil 25%).
| FPSO Cidade de Itaguaí information: | |
| Oil processing: | 150 000 barrels/day |
| Gas treatment and compression: | 8 million m³/day |
| Injection water treatment: | 264 000 barrels/day |
| Storage capacity: | 1.6 million barrels of oil |
| Water depth: | 2 220 meters |
| Total length: | 333 meters |
| Breadth: | 58 meters www.bg-group.com |
Production from the Gullfaks South (GSO) fast-track project for improved oil recovery in the North Sea started on 27 July. GSO will increase the output from the Gullfaks area by around 65 million barrels of oil equivalent.
The Gullfaks A platform in the North Sea. (Photo: Øyvind Hagen)
«GSO demonstrates how we can increase recovery and profitability by use of standardized, simplified development solutions tied to existing infrastructure,” says Arild Dybvig, vice president for fast-track projects in Development & Production Norway. Production started three years after the project was approved. NOK 9 billion have been invested in the project.
«Helping utilize spare processing capacity, the project extends the Gullfaks A platform life beyond 2030,» says Marit Berling, vice president for Gullfaks operations.
GSO represents our focus on improved recovery, standardization and industrialization – in line with Statoil’s continuous effort of maximizing value creation on the Norwegian continental shelf.
This project is part of Statoil’s fast-track portfolio, but it has a larger and more complex subsea scope than ordinary developments of this kind. «Close to 800 vessel days and 2.3 million working hours have been completed with good HSE results. GSO is our most comprehensive fast-track project,» says Trond Bokn, vice president for subsea projects in Technology, Projects & Drilling. The project also involved 370 drilling rig days. The drilling program will continue through the first quarter of 2016.
GSO covers two subsea templates, four production wells, two gas injectors, a gas injection pipeline and a total of three production tubings, in addition to umbilicals and power cables for pipeline heating. There are a total of 22 subsea tie-ins.
After extensive review and under a robust array of safety requirements, Bureau of Safety and Environmental Enforcement (BSEE) Director Brian Salerno announces that Shell has received conditional approval of two Applications for Permits to Drill (APD) to conduct limited exploratory drilling activities in the Chukchi Sea offshore Alaska. Specifically, the APDs limit Shell to drilling only the top sections of wells and prohibit Shell from drilling into oil-bearing zones.
Shell currently is not permitted to drill into oil-bearing zones because, to do so, BSEE requires that a capping stack be on hand and deployable within 24 hours. A capping stack is a critical piece of emergency response equipment designed to shut in a well in the unlikely event of a loss of well control. Shell’s capping stack is staged on the vessel M/V Fennica, which is currently en route to Portland, Oregon, for repairs. If and when the M/V Fennica is capable of being deployed in the Chukchi Sea and Shell is able to satisfy the capping stack requirement, the company may submit an Application for Permit to Modify the APDs and request to have this restriction reconsidered.
“Without question, activities conducted offshore Alaska must be held to the highest safety, environmental protection, and emergency response standards,” said Salerno. “Without the required well control system in place, Shell will not be allowed to drill into oil-bearing zones. As Shell conducts exploratory activities, we will be monitoring their work around the clock to ensure the utmost safety and environmental stewardship.”
In addition to restricting Shell’s ability to work in oil-bearing zones, the APDs also define limitations related to marine mammal protection consistent with requirements established by the U.S. Fish and Wildlife Service (USFWS). Consistent with regulatory requirements, a USFWS Letter of Authorization (LOA) issued on June 30 requires Shell to maintain a minimum spacing of 15 miles between active drill rigs during exploration activities to avoid significant effects on walruses in the region. Under the limited permits granted today, Shell may proceed with drilling the top sections of two wells at the Burger Prospect, Burger J and V as described in the company’s Exploration Plan (EP), which are located less than 15 miles apart. As such, Shell is prohibited from conducting simultaneous drilling activity at these wells. Specifically, Shell must plug and abandon the top section of the first well before proceeding with any drilling activity at the second well site.
Under the LOA, Shell is also required to have trained wildlife observers on all drilling units and support vessels to minimize impacts to protected species. Shell must stay within explicitly outlined vessel operating speeds and report daily regarding all vessel transits.
The APDs were approved only after careful review of the adequacy of Shell’s ice management plans in the absence of the M/V Fennica as well as the consistency of the plans with protections in place for marine mammals. In addition to redundancy provided by other ice management support vessels, Shell will employ aerial reconnaissance over flights, satellite imagery and other measures to monitor ice floes to fulfill the operational goals of the ice management plan in terms of early detection and site safety. The use of these enhanced technologies will allow Shell to meet its operational requirements for ice management, while conforming to the Hanna Shoal Walrus Use Area restrictions identified by the USFWS.
In addition to defining the specific limitations described above, BSEE’s review of the APDs also included thorough analysis of information submitted by Shell – including well casing design, equipment design, testing procedures, safety protocol, third party certifications of key equipment and rig information – for technical adequacy, safety, and environmental compliance. Shell was required to address any issues and inadequacies identified by BSEE before the APDs were approved.
To ensure compliance with this and other conditions of the APDs, BSEE safety inspectors will be present on the drilling units Noble Discoverer and Transocean Polar Pioneer 24 hours a day, seven days a week to provide continuous oversight and monitoring of all approved activities. The inspectors are authorized to take immediate action to ensure compliance and safety, including cessation of all drilling activities, if necessary. BSEE experts have been engaged in thorough inspections of both drilling units and Shell’s response equipment.
The Burger Prospect is located in about 140 feet of water, 70 miles northwest of the village of Wainwright.
BSEE’s close oversight of drilling operations in the Chukchi Sea this year is consistent with its continuing efforts over the past five years to upgrade safety standards to improve the safety of offshore oil and gas development. In addition, building on the lessons learned from Shell’s 2012 drilling operations in the offshore Arctic and incorporating the recommendations of a Departmental review of those activities, BOEM on May 11, 2015, provided conditional approval of Shell’s Exploration Plan that incorporated the safety requirements set forth in Shell’s Exploration Plan and established numerous additional stringent safety requirements that must be met before Shell can drill into oil-bearing zones.
All phases of an offshore Arctic program – preparations, drilling, maritime and emergency response operations – must be integrated and subject to strong operator management and government oversight, as detailed in Shell’s Integrated Operations Plan;
A shortened drilling season to allow time for open-water emergency response and relief rig operations late in the drilling season before projected ice encroachment;
Capping stack must be pre-staged and available for use within 24 hours;
A tested subsea containment system must be deployable within eight days;
The capability to drill a same season relief well;
A robust suite of measures to avoid and minimize adverse impacts to marine mammals and their habitat, impacts to Native subsistence activities, and other environmental impacts;
and Drilling units and their supporting vessels must depart the Chukchi Sea at the conclusion of each exploration drilling season.
The Department has also published proposed regulations to ensure that future exploratory drilling activities on the U.S. Arctic Outer Continental Shelf are done safely and responsibly, subject to strong and proven operational standards and Shell’s Chukchi Sea operations are being held to many of standards in the proposed regulations.
RigNet, Inc. (NASDAQ:RNET), a leading global provider of managed remote communications solutions, telecoms systems integration (TSI) services, and collaborative applications to the oil and gas industry, announced that its RigNet TSI business has been awarded a multi-million dollar contract to deliver communications systems and infrastructure for a greenfield multi-train Gulf Coast LNG liquefaction and export facility. The award of this contract by a leading Texas energy producer continues RigNet's long-term success in the delivery of integrated telecommunications systems for this important part of the United States' energy export infrastructure.
"Every EPC project presents its own unique opportunities and challenges," said Mark Slaughter, RigNet's CEO and President. "Our combination of engineering expertise and broad range of services enables RigNet to provide a single-source, turnkey solution that helps maximize uptime for complex facilities. The long-term relationship with the customer, and experience gained in serving other LNG liquefaction plants, helps RigNet deliver a uniquely high quality outcome."
RigNet TSI's scope of work includes the integration and delivery of critical facility communications infrastructure, including Structured Cabling, Local Area Network (LAN), Wireless LAN (WLAN), Telephony, Public Address/General Alarm (PAGA), Closed Circuit Television (CCTV), Access Control (ACS), Intrusion Detection (IDS), and Personnel Radio systems for this facility, the first of its kind in the Americas.
"This project demonstrates RigNet TSI's ability to deliver proven, reliable and cost-effective communications solutions to the LNG industry," said Gerry Gutierrez, RigNet TSI Group Vice President. "We are proud to be a valued supplier with this energy producer as they expand their capabilities to export American LNG to markets worldwide."
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