Cobalt International Energy, Inc. (“Cobalt”) (NYSE:CIE) has announced it has completed drilling operations on the North Platte #4 appraisal well.
ExxonMobil subsidiary, Esso Exploration and Production Guyana Limited (EEPGL), has announced that it has awarded contracts to SBM Offshore for a floating production, storage and offloading (FPSO) vessel, a key step in moving the Liza field toward first production.
Under the contracts, SBM Offshore will perform front end engineering and design for the FPSO, and, subject to a final investment decision on the project in 2017, will construct, install and operate the vessel.
“Liza development activities are steadily progressing, and we’re excited to reach this important milestone,” said Neil Duffin, president of ExxonMobil Development Company. “We look forward to working with the government of Guyana to develop its valuable resources, which have the potential to provide long-term, sustainable benefits to the country.”
ExxonMobil submitted an application for a production license and its initial development plan for the Liza field in early December. The development plan, submitted to the Guyana Ministry of Natural Resources, includes development drilling, operation of the FPSO, and subsea, umbilical, riser and flowline systems.
The Liza field has a potential recoverable resource estimate in excess of 1 billion oil-equivalent barrels and is located in the Stabroek block approximately 120 miles (193 kilometers) offshore Guyana.
The Stabroek block currently comprises 6.6 million acres (26,800 square kilometers). Esso Exploration and Production Guyana Limited is the operator and holds a 45 percent interest in the Stabroek block. Hess Guyana Exploration Ltd. holds a 30 percent interest, and CNOOC Nexen Petroleum Guyana Limited holds a 25 percent interest.
Aberdeen-based AISUS Offshore has made significant progress in growing its global footprint following the award of 15 contracts and work scopes over the past three months.
The company has reported that 20% of its revenues are now generated by business secured overseas.
Most recently, AISUS completed four J-Tube inspections on a platform located in the Mediterranean Sea for a world leading oil services firm. More than 750m of inspection data was gathered using AISUS’ bespoke crawler-driven inspection system.
Stuart Lawson, Managing Director, AISUS Offshore
AISUS has also completed internal caisson inspection projects in Norway and Denmark, utilizing its custom engineered Aquarius system to perform corrosion mapping over the entire internal surface of the caisson. Prior to the launch of this technology, there was no way to perform full length corrosion mapping on subsea and topside structures in the same deployment.
Stuart Lawson, managing director of AISUS Offshore, commented: "Collectively, these contracts represent an exciting new phase for AISUS as we look to cement our position as one of the industry’s leading inspection specialists, both in the UK sector and overseas.
“Over the past four years, we have worked hard to create a step-change in both technology and application mind-set to deliver precise inspection solutions, whilst reducing costs, without sacrificing the quality of our products or personnel.”
“The requirements for installations to be cost-effective and environmentally secure are ever increasing and monitoring their condition is essential to ensure integrity. Deterioration can be significant, with serious consequences for installation integrity if not managed properly. By challenging conventional and established techniques, and working in collaboration with carefully selected partners, we believe enhancements can always be found.”
“We understand the need to develop technology that maximizes data accuracy and minimizes the duration of offshore inspections to satisfy the rigorous demands of the oil and gas sector, drive down costs and, ultimately, increase production.”
Specializing in the inspection of caissons and risers at all stages of the asset lifecycle, from commissioning, through operations, to decommissioning, AISUS has developed market leading technology, including a diverse range of visual and ultrasonic scanning systems.
Looking ahead, the north-east firm aims to establish strategic local partnerships and operating bases in key international locations over the next three years so it can continue to expand, increase its service offerings and develop the technologies which will help sustain long-term growth.
“Reliable and meaningful inspection data must be acquired in order to make comprehensive integrity assessments of offshore pipework and structures. Asset integrity continues to be a major priority for North Sea operators, and through our wide range of bespoke inspection services we will continue to support the industry to ensure safe and cost-effective operations across the UKCS and beyond,” added Mr. Lawson.
Established in 2013, AISUS Offshore is an innovative, technology driven company delivering remotely deployed visual and ultrasonic inspection solutions to the global oil and gas industry.
Noble Corporation plc (NYSE: NE) has announced that the Company and certain subsidiaries of Royal Dutch Shell plc (NYSE: RDS.A) have agreed to amend the existing long-term contracts on three ultra-deepwater drillships. In the current, challenging environment for offshore exploration and production projects, the agreements offer benefits for both parties.
The contract amendments pertain to the Noble Bully II, Noble Globetrotter I and Noble Globetrotter II, which are operating under 10-year term contracts that commenced in April 2012, July 2012 and September 2013, respectively.
Noble Bully II. Photo credit: Noble Corporation
Under the agreements, dayrates for each rig are now determined by taking the higher of 1) a newly established minimum dayrate, (or floor), or 2) the dayrate adjustment mechanism, as originally included in the contract. The contract amendments for the Noble Globetrotter I and Noble Globetrotter II provide for a dayrate floor of $275,000 per day, representing a minimum market rate if the dayrate adjustment mechanisms for these two rig contracts stay below that level. The Noble Bully II contract contains a floor dayrate, which is $200,000 per day plus daily operating expenses.
Additionally, Shell was granted and has exercised the right to idle the Noble Globetrotter II for a period of up to 730 days, which is expected to occur in January 2017. During the idle period, a negotiated rate of $185,000 per day will be paid. Shell was also granted and is expected to exercise the right to idle the Noble Bully II for a period of up to 365 days, commencing no later than May 2017. The Noble Bully II is part of the Bully joint-venture (Noble 50%, Shell 50%). During this idle period, a negotiated rate of $200,000 per day will be paid. Noble has discretion over each rig's operating costs throughout the idle period, with the flexibility to reduce costs over the anticipated period. If warm stacked, Noble expects daily cost savings on each rig of at least $100,000 per day, with additional cost savings should Noble elect to cold stack the units. In addition, Noble can enter into contracts with third parties for the Noble Globetrotter II and the Noble Bully II during the idle periods. Noble would be responsible for operating expenses and would also retain any incremental revenue received from such third party contracts. Other than the new dayrate floor, no changes were made to the Noble Globetrotter I dayrates.
The dayrate adjustment mechanism, which begins on the five-year anniversary of each of the three contracts, employs an average of market rates experienced over a defined period for a basket of rigs that match a set of distinct technical attributes, with adjustments every six months thereafter until the completion of the 10-year primary terms.
David W. Williams, Chairman, President and Chief Executive Officer of Noble Corporation plc, stated, "This mutually beneficial agreement provides Noble with clarity on dayrates and subsequent operating cash flows through the duration of the contracts on each of the three rigs. We also retain the future upside if the recent oil price recovery drives new market opportunities. These amendments will provide Noble with enhanced financial flexibility at a time when the offshore industry is experiencing a cyclical bottom and the timing of the inevitable recovery remains unknown."
The primary term for each of the drillships Noble Bully II, Noble Globetrotter I, and Noble Globetrotter II are unchanged, with contracts expected to conclude in April 2022, July 2022 and September 2023, respectively.
The Hebron oil field is located offshore Newfoundland and Labrador, Canada in the Jeanne d'Arc Basin.
Kosmos Energy (NYSE:KOS) announces that it has entered into a partnership with BP (LSE:BP) in Mauritania and Senegal that combines Kosmos’ exploration expertise with BP’s deepwater development, and LNG production and marketing experience.
Under the terms of the agreement, BP will assume named operatorship and acquire a 62 percent working interest in Kosmos’ licenses covering blocks C6, C8, C12, and C13 offshore Mauritania, as well as an effective 32.49 percent working interest in the licenses covering the Saint Louis Offshore Profond and Cayar Offshore Profond blocks offshore Senegal. Kosmos will maintain a 28 percent and 32.51 percent effective working interest in the licenses offshore Mauritania and Senegal, respectively, and will continue as exploration operator.
Andrew G. Inglis, Kosmos Energy’s chairman and chief executive officer said: “This agreement with BP demonstrates the value of our strategy, together with the quality of the basin we have opened offshore Mauritania and Senegal. Following a thorough farm-out process, BP emerged as the right partner to help us advance the Tortue gas project at pace and take forward a multi-well exploration program that will test the basin’s liquids potential beginning in mid-2017. We are pleased to have secured a super-major partner that brings financial capability, deepwater development and LNG expertise, and a vision that is fully aligned with the interests of both countries.”
Bernard Looney, BP upstream chief executive said: “The Mauritania-Senegal basin is an asset with world-class scale and potential, and we look forward to working with the team at Kosmos and the governments of Mauritania and Senegal to efficiently explore and develop its full potential. We believe the basin will become an important profit center for our upstream business.”
Under the terms of the agreement, Kosmos will receive fixed consideration of $916 million, including:
$162 million in cash up front;
$221 million carry on exploration and appraisal, including a drill stem test (DST) on Tortue expected to be completed in 2017; and
$533 million maximum carry on development costs until first gas production on the Tortue project, including a front end engineering and design (FEED) study to be completed in 2017 with the objective of reaching a final investment decision (FID) by 2018.
Kosmos will also receive a contingent bonus of up to $2 per barrel, for up to 1 billion barrels of liquids, structured as a production royalty, subject to a future liquids discovery and oil price.
Commenting on the commercial terms of the transaction, Mr. Inglis said: “The transaction strengthens our balance sheet by materially reducing our capital expenditure requirements, effectively funding our Mauritania-Senegal work program for the next several years. The enhanced free cash flow generation will enable us to continue to pursue other growth opportunities in our portfolio with discipline.”
Additionally, Kosmos and BP have entered into an exclusive exploration partnership covering potential new ventures opportunities in Mauritania, Senegal and The Gambia. Kosmos will remain exploration operator of all new ventures acquired within the areas of interest, while BP will become development operator.
Kosmos will provide additional information about the transaction during a conference call on January 4th, 2017 at 10 a.m. EST. The call will be available via telephone and webcast.
Dial-in telephone numbers:
U.S. / Canada: +1.877.407.3982
International: +1.201.493.6780
Webcast: investors.kosmosenergy.com
Closing of the transaction is expected in the first quarter of 2017 with an effective date of July 1, 2016 and is subject to customary conditions including government approvals.
Subsea 7 S.A. (Oslo Børs: SUBC, ADR: SUBCY) announces the award of a sizeable(1) contract by Centrica for the Oda field in the Norwegian North Sea.
The Oda oil field (previously called Butch) was discovered in 2011 in the southern part of the Norwegian North Sea, approximately 14 kilometers east of the Ula field. The contract scope comprises Subsea 7's expertise and capabilities in engineering, procurement, construction, installation and commissioning (EPCIC) of subsea umbilicals, risers and flowlines (SURF) including the production pipeline, water injection line, umbilical and related subsea services.
Project management and engineering will commence immediately from Subsea 7's office in Stavanger, Norway, with offshore operations scheduled to commence in 2018.
Phil Simons, Vice President North Sea & Canada, said: "The strategic partnership with Centrica allows the parties to work closely together to optimize the project delivery. This contract award shows that this way of working with our clients provides cost effective and optimized technical solutions, and earlier delivery of projects. We look forward to continuing to work closely with Centrica to successfully deliver the Oda project, with safety and quality at the forefront throughout the execution."
(1) Subsea 7 defines a sizeable contract as being between USD 50 million and USD 150 million.
Oil production from the Organization of the Petroleum Exporting Countries (OPEC) for November rose for the sixth straight month to a record 33.86 million barrels per day (b/d), according to a survey of OPEC and oil industry officials by S&P Global Platts, the leading independent provider of information and benchmark prices for the commodities and energy markets.
The November production figure was a 320,000 b/d rise from October output and illustrates the challenge OPEC faces implementing a production cut it finalized in Vienna last week with the aim of accelerating the global oil market's rebalancing.
Many members appear to be pumping at or close to their full capacity to maximize revenues before the OPEC deal goes into force January 1.
Under that plan, the organization will, for six months, cut 1.2 million b/d from its October output level, as calculated by an average of OPEC's six secondary sources, including Platts, and freeze production at around 32.5 million b/d.
Saudi Arabia, which has committed to holding its output at 10.046 million b/d, saw its November production drop slightly to 10.52 million b/d, indicating it has a way to go before complying with its target.
Exports of Saudi crude have been high in recent months and output has defied the usual seasonal decline, even with the peak summer air conditioning season long over, though experts expect the country to return to more typical winter consumption patterns to comply with the production cut.
Iraq, OPEC's second largest producer, saw November output hold steady at 4.56 million b/d. The country had disputed secondary source estimates of its production as too low and sought an exemption from the OPEC cuts due to its war against the Islamic State.
But Iraq ultimately agreed to the OPEC plan, which calls for the country to bring production down to 4.351 million b/d, as calculated by secondary sources.
Iran, meanwhile, raised its November production slightly from October to 3.69 million b/d. Iran, which also sought an exemption from the cuts as it aimed to regain its pre-sanctions market share, is allowed to produce up to 3.797 million b/d under the OPEC plan.
Angola showed the biggest rise in production for November, but that was expected as its key Dalia field, which produces around 200,000-250,000 b/d, was scheduled to come back online after going down for maintenance for all of October.
Angola's November production was 1.7 million b/d, up 230,000 b/d from October, with small declines in export volumes offsetting the return of Dalia. Its output target of 1.673 million b/d under the OPEC plan is based on its September level, before Dalia went into maintenance.
Nigeria, exempt from the OPEC cuts as it battles militancy in the Niger Delta, saw its production remain at 1.68 million b/d in November, unchanged from October. The loss of production of key export grade Forcados, which saw a major pipeline bombed in early November, was offset by increased exports of other grades.
Traders say they expect Forcados production to remain offline for a while, with no signs of a January loading program, and the oil-rich Niger Delta remains unstable and sensitive, with chances of more militant attacks on oil infrastructure high.
Libya, also exempt from the cuts, averaged 580,000 b/d in November, up 50,000 b/d from October, as it continues to find its footing after years of civil war.
The country had been producing 600,000 b/d at the beginning of the month, according to state-owned National Oil Corporation, but a power outage November 23 caused output to fall to 523,000 b/d.
Venezuela was the only OPEC member other than Saudi Arabia to see a fall in production, as November output slid to 2.07 million b/d amid the country's economic crisis.
The Platts estimates were obtained by surveying OPEC and oil industry officials, traders and analysts, as well as reviewing proprietary shipping data.
For output numbers by country, click on this S&P Global Platts OPEC Production Table. You may be prompted for a cost-free, one-time-only log-in registration.
Ecopetrol S.A. (BVC: ECOPETROL; NYSE: EC) announces the discovery of oil at the Warrior well located in deepwater of the Green Canyon in the Gulf of Mexico.
Ecopetrol's US subsidiary, Ecopetrol America Inc., owns 20% of the field, operated by Anadarko Petroleum Corporation and Anadarko US Offshore LLC, with a 65% stake. MCX Exploration (USA) LLC has the remaining 15%.
The drilling penetrated a layer of water of 1,263 meters and an extension below the seabed of 6,953 meters, for a total depth of 8,216 meters. The Warrior exploratory well found more than 210 net feet (64 meters) with high quality oil in multiple reservoirs from the Miocene era.
This discovery is a result of Ecopetrol's new exploratory strategy, which includes partnerships with leading global companies to diversify risk, increase exploration and increase likelihood of discovery.
The new strategy seeks hydrocarbons (oil and gas) near existing infrastructure to achieve production in the short term. The Warrior well is expected to take advantage of the production facilities of the Marco Polo platform, also operated by Anadarko.
Ecopetrol is already a partner with 9.21% in another near field, K2, where the Company produces about 2,000 barrels per day. Warrior, K2 and Marco Polo are located within a radius of five kilometers away.
Warrior is the fifth discovery of Ecopetrol in the United States, after Rydberg and Leon in 2014, and Dalmatian South and Parmer in 2012.
In the Gulf of Mexico, Ecopetrol went from producing 3,500 barrels per day in July 2016 to about 12,000 barrels today, demonstrating the region's growing strategic value for the Company. The majority comes from the Gunflint well, in which Ecopetrol America Inc. owns 31.5%.
Ecopetrol increased its stake in Warrior from 15% to 20% in August 2016, within a strategic decision that today brings benefits to the Company.
Decommissioning models are receiving greater attention as challenging economic realities call into question the continued commercial viability of assets already beyond their design lives. On the other side of the equation, the bill for decommissioning is massive for operators worldwide.[1]
In the North Sea alone, it could cost up to USD82 billion (bn) from 2016-2040, with as much as USD51bn of that in the UK sector.[2]
The Norwegian Petroleum Directorate estimates that total decommissioning costs for offshore Norway will be NOK160bn (USD19bn). An equivalent forecast for Gulf of Mexico is USD26bn.[3]
“Experience in this type of activity is still relatively limited,” said Graeme Lamont, business development manager, UK & West Africa, DNV GL - Oil & Gas. “This presents opportunities for greater collaboration, knowledge sharing, and clearer guidance to minimize disruption to neighbouring fields. Activity needs to be carried out in a safe, environmentally conscious and cost-effective way.”
Allseas Pioneering Spirit, which can remove huge topsides and jackets in a single lift, is an innovative response to decommissioning costs. Photo: Allseas
For more than a decade, DNV GL engineers have supported platform removal operations right through from desktop assessments and offshore supervision to environmental and safety studies. Workscopes during dismantling and removal of major topsides have also included studies which balance efforts to control operational and technological risks in various decommissioning phases.
Most recently, the technical advisor has brought its worldwide experience to its role as a workstream ‘champion’ for an online platform being developed by the UK industry forum Decom North Sea (DNS) to facilitate knowledge sharing.
In this capacity, DNV GL vets and manages the quality of content produced by collaborative efforts to make it easier and more cost effective for operators to comply with the UK's regulations governing the cessation of production (CoP) and dismantling and removal of offshore infrastructure.
Regulatory compliance is one of 10 decommissioning workstreams on which operators, contractors and other stakeholders are collaborating to develop DNS’s Late Life Planning Portal (L2P2).
These areas of work require attention and management as a company and its assets move from normal operations through late life to CoP and decommissioning.
Once online, L2P2 will help oil and gas professionals to plan and execute projects. Its development marks a change in the mind-set of companies. “They are starting to understand the value of collaboration,” said Karen Seath, general manager, DNS.
She added: "The cost and complexity of decommissioning is forcing a long, hard think about how best to utilize capabilities and resources. The sector is realizing that effective collaboration can achieve things much more cost efficiently and effectively than going it alone.”
One operator and contractor have co-located their teams working on a major North Sea decommissioning project offshore UK, and aligned organizational structures for the duration, for example.
“We are also seeing port owners and public agencies collaborate with contractors and suppliers to improve onshore locations as logistics hubs for decommissioning,” Seath said.
“L2P2 is a true collaborative knowledge hub for sharing tools, experiences, lessons and new ideas to help plan and execute decommissioning projects. Case studies from completed projects will help others by sharing what went well and not so well,” she said.
The regulatory compliance workstream recommends that operators should start monitoring UK regulations more than 10 years before CoP, said Lamont.
“Experience reflected in the L2P2 suggests that preliminary regulatory discussions in the UK should best take place between about five to 10 years before CoP, and that a draft decommissioning programme should be drawn up three to five years before production ceases. Formal submission to regulators is around three years before CoP, and regulatory compliance still needs managing after last oil or gas has flowed.”
Regulatory compliance meshes with other workstreams: business strategy; commercial; liability economics; project management; production operations; well plug and abandonment; contracting strategy; technology; and stakeholders. These are aligned in the L2P2 so users can see what could or should happen in each workstream at milestones along a timetable reflecting good practice based on industry experience.
Proof of the L2P2 concept is due online in May 2016. A landing page for the portal will signpost visitors to content supporting any function or timeframe of the decommissioning process.
The scale of decommissioning activities DNV GL supports globally has ranged from whole platforms to individual work packages and isolated subsea infrastructure. High profile completed or ongoing North Sea decommissioning projects with DNV GL involvement include: in the UK – Amethyst, Maureen, Miller, Murchison, NW Hutton, and Welland; offshore Norway – Asgard, Ekofisk and Frigg.
Recommended practices and service specifications relevant to aspects of offshore decommissioning include: DNV-RP-H101 Risk management in marine and subsea operations; DNV-RP-H102 Marine operations during removal of offshore installations; DNV-RP-H103 Modelling and analysis of marine operations; and DNV-OSS-300 Risk-based verification.
Also, the Offshore Standard, DNV-OS-H102 Marine operations,design and fabrication was published in 2012. A DNV GL Guideline, Risk based abandonment of offshore wells, was issued in 2015.5
[1] ‘Decom provisions on the rise, report oil majors’, decomworld.com, 16 March 2016
[2] ‘North Sea decommissioning market forecast 2016-2040’, Douglas-Westwood, February 2016
[3] ‘Offshore decommissioning report 2015: Gulf of Mexico 6th edition’, Mark J Kaiser, Decomworld, March 2015
Shell has started oil production from the Malikai Tension-Leg Platform (TLP), located 100-kilometers off the coast of the Malaysian state of Sabah.
Located in waters up to 500-metres deep, Malikai is Shell’s second deep-water project in Malaysia, following the successful start-up of the Gumusut-Kakap platform in 2014. Malikai is expected to have a peak production of 60,000 barrels per day. As the company’s first TLP in the country, Malikai is an example of the strength of Shell’s global deep-water business, applying TLP expertise from decades of operations in the U.S. Gulf of Mexico.
Malikai Tension Leg Platform starts production. Photo courtesy: Shell
“Malikai marks an important milestone for Shell, its partners, Sabah and Malaysia. The project has demonstrated our capability in delivering competitive deep-water projects utilizing our global expertise.” said Andy Brown, Upstream Director, Royal Dutch Shell.
The project features a cost-effective platform design and a unique, industry-first set of risers, or pipes that connect the platform to the wells for oil production, which required fewer drilling materials and lower costs.
Designed and built in Malaysia, the Malikai TLP project has allowed Shell to share deep-water expertise with Malaysian energy companies, playing an active role in helping the government develop the nation’s deep-water resources and deep-water service industry.
The Malikai project is a joint venture between Shell (35%, operator), ConocoPhillips Sabah (35%) and PETRONAS Carigali (30%).
Globally, Shell’s deep-water business is a growth priority for the company and currently produces 600,000 boe/d. Deep-water production is expected to increase to more than 900,000 boe/d by the early 2020s from already discovered, established reservoirs. Two other Shell-operated projects are currently under construction or undergoing pre-production commissioning: Coulomb Phase 2 and Appomattox in the U.S. Gulf of Mexico. In September 2016, Shell announced the start of production at Stones in the Gulf of Mexico, the world’s deepest offshore oil and gas project beneath 2,900 meters of water.
For more information on Shell’s deep-water projects around the world visit: www.shell.com/deepwater
The Bureau of Ocean Energy Management (BOEM) completed its required evaluation to ensure the public receives fair market value for tracts leased in Western Gulf of Mexico Oil and Gas Lease Sale 248, held on August 24, 2016.
After extensive geological, geophysical, engineering, and economic analysis, BOEM has awarded all 24 leases on tracts covering 138,240 acres to high bidders who participated in the sale. The accepted high bids are valued at $18,067,020. BOEM accepted the 24 bids after determining that the value of each bid was sufficient to provide the public with fair market value for each tract. The highest bid accepted was $1,124,000, submitted by Exxon Mobil Corporation for East Breaks, Block 590. BHP Billiton Petroleum (Deepwater) submitted 12 of the 24 bids.
During the sale, three companies submitted 24 single bids totaling $18,067,020. No bids were received in water depths less than 800 meters or greater than 1,600 meters. By comparison, during last year’s Western Sale 246, 33 tracts received single bids totaling $22,675,212. Five of the bids were in water depths less than 800 meters and 21 were in water depths greater than 1,600 meters. For more information on Sale 248 click here.
U.S. Secretary of the Interior Sally Jewell applauded President Obama’s announcement that he is withdrawing offshore areas in the Atlantic and Arctic Oceans from future mineral extraction to protect these ecologically sensitive marine environments from the impacts of any future oil and gas exploration and development.
Photo credit: Patrick Kelley, USCG
The withdrawal does not restrict other uses of these federal waters on the Outer Continental Shelf, and will help to sustain commercial and recreational fisheries in the Atlantic to support fishing-dependent communities, as well as the harvest of marine resources on which many Alaska Native communities rely for subsistence use and cultural traditions.
“The President’s bold action recognizes the vulnerable marine environments in the Arctic and Atlantic oceans, their critical and irreplaceable ecological value, as well as the unique role that commercial fishing and subsistence use plays in the regions’ economies and cultures,” Secretary Jewell said. “The withdrawal will help build the resilience of these vital ecosystems, provide refuges for at-risk species, sustain commercial fisheries and subsistence traditions, and create natural laboratories for scientists to monitor and explore the impacts of climate change.”
The withdrawal areas announced encompass 3.8 million acres in the north and mid-Atlantic Ocean off the East Coast and 115 million acres in the U.S. Arctic Ocean. Including previous presidential withdrawals, today’s action protects nearly 125 million acres in the offshore Arctic from future oil and gas activity.
In the Atlantic, the withdrawal decision protects 31 canyons, extending from Heezen Canyon offshore New England to Norfolk Canyon offshore of the Chesapeake Bay. The largest, Hudson Canyon, reaches depths greater than 10,000 feet, comparable in scale to the Grand Canyon, which is 6,093 feet at its deepest. The canyons are regions of enhanced biodiversity, home to numerous species including deep-water corals, deep-diving beaked whales, commercially valuable fish, and significant numbers of habitat-forming soft and hard corals, sponges and crabs.
The canyon region is home to several fish stocks managed as Highly Migratory Species, including commercially valuable marlin, sailfish, swordfish, tuna and sharks. These geologic features also provide important habitat for a number of protected species including beaked, sperm and sei whales, many of which show an affinity to canyon ecosystems as compared to other Atlantic waters.
The President’s action will preserve critical ecological hot spots, helping to protect habitats important to Atlantic fisheries. The designation also affords long-term opportunity for research and exploration, and helps ensure that species dependent on the canyon habitats are protected. It also builds on protections established by the recent creation of the Frank R. Lautenberg Deep Sea Coral Protection Area. This protected region, created by the Mid-Atlantic Regional Fishery Management Council and approved by NOAA, prohibits bottom trawling in all the canyons in the region.
In addition to numerous requests from local and regional officials to protect these offshore resources, 145 prominent marine scientists issued a public letter in September 2015, voicing their conclusion that the threats to the unique marine environment in this region warranted permanent protection to preserve intact ecosystems. These concerns are informed by a number of research findings, including a National Oceanic and Atmospheric Administration study that found ocean temperatures in the Northeast U.S. Shelf are projected to warm three times faster than the global average and a climate vulnerability assessment on fish and invertebrate species in the region that concluded warming oceans due to climate change threaten the majority of fish species in the area, including salmon, lobster, and scallops. The President’s action builds on his establishment of the Northeast Canyons and Seamounts Marine National Monument, which protects 4,913 square miles of marine ecosystems located 130 miles southeast of Cape Cod. The withdrawal protects major Atlantic canyons that are not in the National Monument.
The President’s Arctic withdrawal, which encompasses the entire U.S. Chukchi Sea and significant portions of the U.S. Beaufort Sea, will provide critical protection for these vibrant and fragile offshore ecosystems, which are home to marine mammals and other important ecological resources and marine species on which many Alaska Native communities rely for subsistence and cultural traditions. These include several species of seals; Pacific walrus; polar bears; more than 98 fish species; a number of whale species, such as the bowhead, gray and beluga; many bird species, including waterfowl such as eiders, long-tailed duck and geese; and shorebirds such as the red-necked phalarope.
“Risks associated with oil and gas activity in the remote, harsh and undeveloped Arctic are not worth taking when the nation has ample energy sources near existing infrastructure,” said Abigail Ross Hopper, the Director of Interior’s Bureau of Ocean Energy Management. “Oil spill response and clean-up raises unique challenges in the Arctic and a spill could have substantial impacts on the region, particularly given the ecosystem fragility and limited available resources to respond to a spill.”
The withdrawal does not affect existing leases in these federal offshore waters and would not affect a nearshore area of the Beaufort Sea, totaling about 2.8 million acres, that has high oil and gas potential and is adjacent to existing state oil and gas activity and infrastructure. While there are significant concerns about oil and gas activity occurring in this area, it will be subject to additional evaluation and study to determine if new leasing could be appropriate at some point in the future. Interior’s five year offshore leasing program for 2017-2022 does not include lease sales in this area or in the withdrawn areas.
The U.S. Arctic Ocean is characterized by harsh environmental conditions, geographic remoteness, and a relative lack of fixed infrastructure and existing oil and gas operations. Despite the substantial steps this Administration has taken to improve the safety of potential Arctic exploration, there would still be significant risks associated with offshore drilling operations and the consequences of an oil spill in this region could be substantially detrimental to the ecosystem.
Climate change-induced temperature increases are occurring fastest in Polar Regions, including the U. S. Arctic, resulting in a disproportionate amount of changes to the Arctic environments, including reduction in seasonal ice cover. Loss of sea ice coverage reduces the available habitat for ice-dependent species such as seals, polar bears, and Pacific walrus. Such conditions and stressors may increase the vulnerability of these species and habitat and reduce their resilience to impacts of oil and gas activities. The Arctic withdrawals build on past actions the President has taken to protect fragile ecosystems and build resilience in the face of climate change, including the Northern Bering Sea Climate Resilience Area; Chukchi and Beaufort Seas areas placed off limits to oil and gas leasing earlier this year; and the Bristol Bay withdrawal in 2014.
Further scientific analysis related to the President’s withdrawal proclamation is available here for the Arctic and here for the Atlantic.
Maps of the areas related to President’s withdrawal proclamation are available here for the Arctic and here for the Atlantic.
Saipem Limited, a subsidiary of Saipem SpA, has been awarded a new contract in the North Sea utilizing the Saipem 7000, reinforcing Saipem’s presence in this highly strategic area where the Company has a long operating history.
Located in the UK sector of the North Sea, the Project is an EPRD contract for the decommissioning of the topsides and jacket of BP’s Miller Platform. The Saipem 7000 is one of the most technologically advanced vessels in Saipem’s fleet. It is equipped with a dynamic positioning system, has a 14,000-ton lifting capacity, and is capable of laying subsea pipelines in ultra-deep waters.
The use of the Saipem 7000 for projects such as the Miller Project eliminates the need for additional cargo barges and allows operations to be conducted in a much safer manner and in a less restrictive weather window. Over the last decade, Saipem has performed a variety of major decommissioning projects, including the Frigg Field decommissioning and, more recently, the removal of the Ekofisk 2/4 S jacket and the Ekofisk 2/4 G bridge.
Saipem Limited currently employs over 800 people, has operated in the UK since 1983 with offices in London and Aberdeen, and will carry out project management, engineering and operations work. For 2017 the Saipem 7000 has already been contracted to execute topside transportation and installation, decommissioning and renewable energy projects in the North Sea.
“Saipem, through its subsidiary Saipem Limited based in the UK, is pleased to see further traction in the decommissioning market with the BP Miller EPRD Project. The award builds on our experience in delivering decommissioning projects successfully and safely over recent years. When coupled with Saipem’s track record in the renewable energy sector, this strengthens the Group’s diversification, and assists our clients and, indeed, the countries in which we operate in the safe, environmentally responsible and cost effective removal of ageing infrastructure”, stated Stefano Porcari, Saipem Offshore Business Unit Executive Vice President.
EnerMech has been awarded its first contract by Subsea 7 in the Australian oil and gas market.
The mechanical engineering group will perform a range of subsea flowline and umbilical pre-commissioning on the Woodside-operated North West Shelf (NWS) Project’s Persephone project and North Rankin Complex in Western Australia.
The workscope includes flooding, hydro-testing and dewatering of flow lines & well jumpers and testing all hydraulic, electrical and optical cores on the main line umbilical, EFL’s and HFL’s with work expected to start this month (December).
EnerMech is one of the foremost suppliers to large scale oil, gas and LNG projects in Australia and has seven bases in-country, including Perth, Melbourne, Darwin and Gladstone.
The company already undertakes specialist testing work on the North Rankin Complex for Wood Group PSN so can offer continuity and familiarity with Woodside and North Rankin requirements.
EnerMech’s Australia regional director, Allan Hart, said: “As a company, we have a strong relationship with Subsea 7 in the major international oil and gas producing hubs and we are delighted to consolidate this link with our first contract award in Australia.
“We place a heavy emphasis on innovation and trying to find fresh solutions to client requirements and our proposal fitted well with Woodside’s specification for the flooding, cleaning and testing of offshore pipelines.
“Our strong reputation for competent umbilical testing, investment in the latest equipment and a collaborative approach to delivery, has put us in a good positon to win other strategic contracts on major Australian oil and gas projects.”
BP has sanctioned the Mad Dog Phase 2 project in the United States, highlighting its long-term commitment to the country despite the current low oil price environment.
Mad Dog Phase 2 will include a new floating production platform with the capacity to produce up to 140,000 gross barrels of crude oil per day from up to 14 production wells. Oil production is expected to begin in late 2021.
Photo credit: BP
“This announcement shows that big deepwater projects can still be economic in a low price environment in the U.S. if they are designed in a smart and cost-effective way,” said Bob Dudley, BP Group Chief Executive. “It also demonstrates the resilience of our strategy which is focused on building on incumbent positions in the world’s most prolific hydrocarbon basins while relentlessly focusing on value over volume.”
In 2013, BP (operator, with 60.5 percent working interest) and co-owners, BHP Billiton (23.9 percent) and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc. (15.6 percent), decided to re-evaluate the Mad Dog Phase 2 project after an initial design proved too complex and costly. Since then, BP has worked with co-owners and contractors to simplify and standardize the platform’s design, reducing the overall project cost by about 60 percent. Today, the leaner $9 billion project, which also includes capacity for water injection, is projected to be profitable at or below current oil prices.
“Mad Dog Phase 2 has been one of the most anticipated projects in the U.S. deepwater and underscores our continued commitment to the Gulf of Mexico,” said Richard Morrison, president of BP’s Gulf of Mexico business. “The project team showed tremendous discipline and arrived at a far better and more resilient concept that we expect to generate strong returns for years to come, even in a low oil price environment.” While BP has reached a final investment decision (FID) on Mad Dog Phase 2, BHP Billiton and Chevron, for the Union Oil Company of California interest, are expected to make a final investment decision in the future.
BP discovered the Mad Dog field in 1998 and began production there with its first platform in 2005. Continued appraisal drilling in the field during 2009 and 2011 doubled the resource estimate of the Mad Dog field to more than 4 billion barrels of oil equivalent, spurring the need for another platform at the field. The second Mad Dog platform will be moored approximately six miles to the southwest of the existing Mad Dog platform, which is located in 4,500 feet of water about 190 miles south of New Orleans. The current Mad Dog platform has the capacity to produce up to 80,000 gross barrels of oil and 60 million gross cubic feet of natural gas per day.
BP plans to add approximately 800,000 net barrels of oil equivalent per day of new production globally from projects starting up between 2016 and 2020.
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