U.S. Secretary of the Interior Ryan Zinke announced that the Department will offer 75.9 million acres offshore Texas, Louisiana, Mississippi, Alabama, and Florida for oil and gas exploration and development. The region-wide lease sale scheduled for August 16, 2017 will include all available unleased areas in federal waters of the Gulf of Mexico and provide a reduced royalty rate for shallow water leases to encourage exploration and production under current market conditions.
Lease Sale 249, scheduled to be livestreamed from New Orleans, will be the first offshore sale under the National Outer Continental Shelf (OCS) Oil and Gas Leasing Program for 2017-2022. Under this program, ten region-wide lease sales are scheduled for the Gulf, where resource potential and industry interest are high, and oil and gas infrastructure is well established. Two Gulf lease sales will be held each year and include all available blocks in the combined Western, Central, and Eastern Gulf of Mexico Planning Areas.
On June 29, President Donald J. Trump and Secretary Zinke announced the public comment period for a new Five-Year National OCS Oil and Gas Leasing Program. The comment period is the first step in executing the new program. The 2017-2022 Program, which begins with the lease sale announced today, will continue to be executed until the new National OCS Oil and Gas Leasing Program is complete.
"Our Outer Continental Shelf lands offer vast energy development opportunities and we are committed to encouraging increased energy exploration and production in these offshore areas to maintain the Nation’s global dominance in energy production," Secretary Zinke said. "As a global energy leader, we will foster energy security and resilience for the benefit of the American people. A strong offshore energy plan that responsibly harnesses more of our resources will spur economic opportunities for industry, states, and local communities, creating jobs and revenue. That's why we also are developing a new national Outer Continental Shelf oil and gas program that will best meet our future energy needs."
Lease Sale 249 will include about 14,220 unleased blocks, located from three to 231 miles offshore, in the Gulf’s Western, Central and Eastern planning areas in water depths ranging from nine to more than 11,115 feet (three to 3,400 meters). Excluded from the lease sale are blocks subject to the Congressional moratorium established by the Gulf of Mexico Energy Security Act of 2006; blocks that are adjacent to or beyond the U.S. Exclusive Economic Zone in the area known as the northern portion of the Eastern Gap; and whole blocks and partial blocks within the current boundary of the Flower Garden Banks National Marine Sanctuary.
"To advance commonsense domestic energy production, the terms of this sale have been developed through extensive environmental analysis, public comment, and consideration of the best available information,” said Counselor to the Secretary on Energy Policy Vincent DeVito. “This will ensure appropriate resource development and further our energy dominance strategy.”
The Gulf of Mexico OCS, covering about 160 million acres, has technically recoverable resources of 550 million barrels of oil and 1.25 trillion cubic feet of gas, accounting for nearly three-fourths of the oil and a fourth of the natural gas produced on federal lands.
The lease sale terms include stipulations to protect biologically sensitive resources, mitigate potential adverse effects on protected species, and avoid potential conflicts associated with oil and gas development in the region. Additionally, BOEM has included appropriate fiscal terms that take into account market conditions and ensure taxpayers receive a fair return for use of the OCS. These terms include a 12.5 percent royalty rate for leases in less than 200 meters of water depth, and a royalty rate of 18.75 percent for all other leases issued pursuant to the sale.
The 12.5 percent royalty rate for leases in less than 200 meters is lower than the proposed 18.75 percent royalty rate for shallow water leases that BOEM published in the Proposed Notice of Sale. The purpose of this change is to adjust the royalty rate to reflect recent market conditions, thereby encouraging competition and continuing to receive a fair and equitable return on oil and gas resources.
"The rate change reflects this Administration's willingness to swiftly respond to economic indicators,” said DeVito. “The 12.5 percent royalty rate is closer in harmony with the current market and federal onshore lease sales.”
As of July 3, 2017, 15.6 million acres on the U.S. OCS are under lease for oil and gas development (2947 active leases) and 4.1 million of those acres (842 leases) are producing oil and natural gas. More than 97 percent of these leases are in the Gulf of Mexico; about 3 percent are on the OCS off California and Alaska.
All terms and conditions for Gulf of Mexico Region-wide Sale 249 are detailed in the Final Notice of Sale (FNOS) information package, which is available here. Copies of the FNOS maps can be requested from the Gulf of Mexico Region’s Public Information Unit at 1201 Elmwood Park Boulevard, New Orleans, LA 70123, or at 800-200-GULF (4853).
The Notice of Availability of the FNOS is available today for inspection in the Federal Register here and will be published in the Federal Register on July 17, 2017.
Image credit: Staatsolie
Exxon Mobil Corporation (NYSE:XOM) announces that its subsidiary ExxonMobil Exploration and Production Suriname B.V., along with co-venturers Hess and Statoil, signed a production sharing contract for Block 59 with Staatsolie Maatschappij Suriname N.V., the national oil company of Suriname. The block adds significant acreage to ExxonMobil’s operated portfolio in the Guyana-Suriname Basin.
Deepwater Block 59 is in water depths ranging from nearly 2,000 meters to 3,600 meters, located approximately 190 miles (305 kilometers) offshore Suriname’s capital city, Paramaribo. The block is 2.8 million acres, or 4,430 square miles, and shares a maritime border with Guyana, where ExxonMobil is the operator of three offshore blocks, including the world-class Liza field discovered by ExxonMobil in 2015.
“We look forward to working with Staatsolie and our co-venturers to evaluate the potential of this new acreage,” said Steve Greenlee, president of ExxonMobil Exploration Company. “Adding this block enhances our leading global deepwater portfolio.”
Suriname represents a new country for ExxonMobil’s upstream business. The company has investments throughout South America. Following contract signing, the co-venturers are preparing to begin exploration activities, including acquisition and analysis of seismic data.
ExxonMobil and consortium partners Hess and Statoil each hold a third of the interest in the block. ExxonMobil is the operator.
Leading marine Offshore services company, BOURBON has entered into a Memorandum of Understanding (MOU) with Automated Ships Ltd to support the building of the world’s first autonomous, fully-automated and cost-efficient prototype vessel for offshore operations, in collaboration with the project’s primary technology partner, KONGSBERG.
BOURBON will leverage its expertise in building and operating a standardised fleet to provide detailed input to the development and design of the Hrönn project, ensuring flexibility, reliability and cost efficiency to operate safely and effectively in the demanding offshore environment. Based on its customer experience, BOURBON will thus help to match client demand.
In the second phase of the project, BOURBON and ASL will join forces to search the subsidies to finance the effective construction of the prototype.
Hrönn is a light-duty, offshore utility ship servicing the offshore energy, hydrographic & scientific and offshore fish-farming industries. It can also be utilised as a ROV and AUV support ship and standby vessel, able to provide firefighting support to an offshore platform working in cooperation with manned vessels. Automated Ships Ltd has progressed the original catamaran design of Hrönn since the project launch on 1st November 2016, opting for a monohulled vessel of steel construction, to provide more payload capacity and greater flexibility in the diverse range of operations.
BOURBON’s entry to the Hrönn project, follows the recent news that it has joined forces with KONGSBERG in a new collaboration to develop digital solutions for next generation connected and autonomous vessels. The two companies will execute joint projects to develop new ways of efficient operations in the offshore services industry, with a fast time-to market.
KONGSBERG will contribute its technology expertise and deliver all major marine equipment necessary for the design, construction and operation of Hrönn, including all systems for dynamic positioning and navigation, satellite and position reference, marine automation and communication. Its vessel control systems including K-Pos dynamic positioning, K-Chief automation and K-Bridge ECDIS and Radar will be replicated at an Onshore Control Centre, allowing full remote operations of Hrönn.
Hrönn’s Sea trials will take place in Norway’s officially designated automated vessel test bed in the Trondheim fjord and will be conducted under the auspices of DNV GL and the Norwegian Maritime Authority (NMA). The Hrönn will ultimately be classed and flagged, respectively.
“In this era of digitalization of industrial services, we are pleased to join this forward-looking project thus demonstrating the positioning of BOURBON as a world reference in terms of operational excellence and customer experience,” said Gael Bodénès, Chief Operating Officer, BOURBON Corporation.
“BOURBON is a world leading marine services company and we are confident that alongside KONGSBERG as technology lead, they will provide a valuable contribution to the design and operation of Hrönn,” said Brett Phaneuf, CEO, Automated Ships Ltd.
“We are pleased to be collaborating with such expert partners in the development of Hrönn, a vessel that will show how digitalisation and autonomy have the potential to revolutionise the offshore services market,” said Stene Førsund, EVP Global Sales and Marketing, Kongsberg Maritime.
Bibby Offshore, a leading subsea services provider to the oil and gas industry, has announced a multimillion pound contract with a global energy player, Maersk Oil UK, to provide both late life production enhancement and decommissioning support in the North Sea.
Barry Macleod, UKCS managing director at Bibby Offshore
The contract saw Bibby Offshore’s diving support vessel Bibby Polaris operate at two separate locations, undertaking production system isolations and critical component replacements to facilitate late life production enhancement, together with comprehensive decommissioning support, which includes subsea deconstruction and infrastructure recovery.
Completed in early July, the projects represented the latest in a number of contracts the client has awarded Bibby Offshore within the past 12 months.
Barry Macleod, UKCS managing director at Bibby Offshore, said: “We have successfully completed multiple projects with this customer, with the latest contract demonstrating their confidence in our late life management and decommissioning expertise.
“This is a significant contract for Bibby Offshore. Whilst our relationship with this respected client continues to strengthen, the award is also clear recognition of our commitment to – and capabilities within - the next stage of safe, efficient and cost-effective North Sea management.”
After a comprehensive review and consideration of comments received from the public, stakeholders, and Federal and state partner agencies and tribes, the Bureau of Ocean Energy Management today conditionally approved a Beaufort Sea exploration plan (EP) it received from Eni US Operating Co. Inc.
Eni US is a subsidiary of Italian multinational oil and gas company Eni S.p.A. In its plan, Eni describes its intent to drill four exploration wells into the federal submerged lands of the Beaufort Sea from its Spy Island Drillsite, a pre-existing facility located in Alaska state waters. Drilling will be conducted during the winter months only. The drilling is scheduled to begin in December 2017.
Over the past 30 days BOEM has been carefully evaluating the EP in accordance with federal law and regulations. This evaluation included a site-specific Environmental Assessment (EA) of the proposed exploration activities pursuant to the National Environmental Policy Act. The EA concluded with a Finding of No Significant Impact (FONSI).
“Eni brought to us a solid, well-considered plan,” said BOEM’s acting director, Walter Cruickshank. “We know there are vast oil and gas resources under the Beaufort Sea, and we look forward to working with Eni in their efforts to tap into this energy potential.”
The evaluation also included two separate public comment periods: one to give the public the opportunity to provide information on issues that should be examined in the Environmental Assessment; and one to comment on the EP itself. This input was carefully considered throughout the process.
“I’d like to thank our Alaska Native stakeholder organizations, environmental groups, members of industry and everyone else who took the time to submit substantive comments,” said James Kendall, director of BOEM’s Alaska OCS Region. “Our staff worked very diligently to analyze every one we received, and incorporate that input into our review.”
The EP and supporting documents, and links for viewing the public comments, are available here. An EP describes all exploration activities planned by the operator for a specific lease or leases, including the timing of these activities, information concerning drilling processes, the surface location of each planned well, and actions to be taken to meet important safety and environmental standards and to protect access to subsistence resources. An EP does not allow an operator to produce oil if any is found; for that, an operator is required to obtain approval of a Development and Production Plan (DPP).
Among the conditions of approval is the requirement that Eni must also procure all appropriate permits from other state and federal agencies, including permits to drill from the Bureau of Safety and Environmental Enforcement. A list of the permits Eni intends to apply for is located in Table A-1 of the EP. A full list of conditions of approval can be found in the approval letter at the link above.
Spy Island is one of four oil- and gas-producing artificial islands in the waters of the Beaufort Sea. The others are Northstar Island, Endicott Island, and Oooguruk Island. The construction of a fifth island, as proposed in a DPP submitted to BOEM by Hilcorp Alaska LLC, is under review by federal agencies.
Shell Offshore, Inc. announces that its affiliate, Shell E and P Offshore Services B.V., will exercise a contractual right to purchase the Turritella floating, production, storage and offloading (FPSO) vessel from SBM Offshore. The vessel is contracted for the Stones deep-water development in the Gulf of Mexico, which began production last year. Shell and SBM will work over the next several months to achieve a safe, smooth transition of the vessel operations.
Transitioning the ownership and operations of the vessel to Shell affiliates allows the company to pursue additional efficiencies and achieve cost improvements to deliver shareholder value at Stones with a continued commitment to operational excellence and safety. The Stones development is the world’s deepest offshore oil and gas project and is scheduled to deliver approximately 50,000-barrels of oil equivalent per day (boe/d) by the end of this year.
The Turritella FPSO has a daily production capacity of approximately 60,000 barrels of oil and 15 million cubic feet of natural gas and fits well within Shell’s global, deep-water portfolio, which includes operations in the Gulf of Mexico, Brazil, Nigeria, and Malaysia. Competitive, deep-water oil resources are a growth priority for Shell with global production expected to reach more than 900-thousand boe/d by the early 2020s.
Currently, Shell has three additional Gulf of Mexico deep-water projects under construction – Appomattox, Kaikias, and Coulomb Phase 2 – as well as options for additional subsea tiebacks and Vito, a potential, new hub in the region.
Statoil and partners ENI and Petoro have made a small gas discovery in the Blåmann well, between the Snøhvit and Goliat fields in the Barents Sea. Recoverable volumes are estimated at 2-3 billion standard cubic meters (BCM), approximately 10-20 million barrels of oil equivalent (BOE).
Image credit: Statoil
The well was drilled in license PL 849, awarded in 2016 in Norway’s Awards in Predefined Areas (APA) licensing round. Gas was found in a 23 meter column in the Stø formation. No oil volumes were encountered.
“We were exploring for oil and this is not the result we were hoping for,” says Jez Averty, senior vice president for exploration in Norway and the UK.
“However, this gas discovery has the potential to contribute additional resources to the Snøhvit project,” he notes.
The discovery is located in the Hammerfest basin, approximately 21 kilometers southeast of the Snøhvit field.
This is the second discovery in Statoil’s 2017 Barents Sea exploration campaign, following the Kayak oil discovery announced on 3 July.
The well was drilled by the “Songa Enabler” semisubmersible drilling rig, which will now move on to the Hoop area to drill the Gemini North prospect in license PL855, northeast of the Wisting discovery.
Licensees Blåmann (PL849): Statoil (operator) 50%, ENI 30% and Petoro 20%
Licensees Gemini North (PL855): Statoil (operator) 55%, OMV 25% and Petoro 20%
Marsol International, a UAE-based global marine solutions provider focused on the offshore oil terminal market and related infrastructure, has signed a two-year contract with Oman Oil Company Exploration & Production LLC (OOCEP) for the provision and management of the marine and offshore activities related to the tanker loading, via the single point mooring (SPM) offshore marine terminal including maintenance works, vessels, equipment, and manpower.
Mike Young, Director of Marsol International, said: “Following the successful exportation of the first and second crude oil from the Musandam gas plant we are delighted to have been selected to support OOCEP for the next two years. Our tanker operations and our product transfer services ensure safe and efficient mooring and unmooring at the SPM and are a crucial element of our asset integrity management service.”
The Musandam gas plant, located on the west coast of the Musandam Peninsula, has a processing capacity of up to 20,000 barrels of crude; 45 million cubic feet of gas and 75 tons of LPG per day.
Statoil Brasil Oleo e Gas Ltda has awarded Seadrill rig contracts for exploration drilling in the BM-S-8 license in the Santos basin.
The agreement includes two contracts: Seadrill Offshore AS will provide the drillship West Saturn and Seadrill Serviços de Petroleo Limitada will provide services on board. The fixed contract scope includes one exploration well and one drill stem test, which are part of the license commitments of the exploration phase. The BM-S-8 license contains parts of the Carcará pre-salt oil discovery.
The West Saturn drillship. (Photo: Seadrill)
The West Saturn is a 6th generation ultra-deepwater drillship, built in 2014 and equipped to drill in water depths of up to 12,000 feet (3600 meters). Commencement date for the contracts is planned between 1 December 2017 and 1 March 2018. Under the contract, Statoil intends to drill the independent Guanxuma prospect.
“Clearly it is not a given that we find what we hope for, but if we are successful Guanxuma could be another significant discovery in this highly prolific basin,” said vice president for exploration in Brazil, Ana Serrano Onate.
Following the Guanxuma well, Statoil plans to perform a drill stem test on the Carcará discovery.
“Testing the Carcará discovery will provide important information for developing the field. In addition, Statoil is evaluating its options for the Northern open area licensing round, expected in October 2017. We believe Statoil is well-positioned for future operatorship of a unitized Carcará field,” said Anders Opedal, country manager for Brazil.
In addition to the firm program, the contracts include options for seven more exploration wells. Statoil can exercise these options based on the results of the firm exploration program and may deploy the West Saturn across its Brazilian assets, given regulatory approval. “Securing this optional rig capacity demonstrates Statoil’s commitment to follow-up on potential exploration success in the 2017-2018 program,” Opedal added.
On 12 July, Statoil announced an agreement that will increase the company’s interest in the BM-S-8 license from 66% to 76%.
Statoil has been present in Brazil for over 15 years and built a robust portfolio, including the Peregrino field in Campos basin and assets in the exploration and development phase. In this period, the company has invested more than 10 billion USD, paid almost 1 billion USD of government take and employed more than 1.000 people either directly or indirectly.
Xodus Group has won a contract with Cairn Oil and Gas of Vedanta Ltd to conduct exploration and appraisal work on its Rajasthan block in north-west India over the next two years.
The first stage of the work will focus on delivering new drilling prospects and an exploration drilling plan, in partnership with Cairn Oil and Gas’ in-house team. Subsequent stages, which will likely commence in 2018, will require project management of the drilling programme in the field as well as subsurface analysis of drilling results.
The work will largely be undertaken from Xodus' offices in London and The Hague with regular visits to Cairn Oil and Gas’ offices near New Delhi for workshops.
Xodus Group CEO, Wim van der Zande
Xodus Group CEO, Wim van der Zande said: “We are pleased to be supporting Cairn Oil and Gas in the pursuit of increasing discovered hydrocarbon resources in the Rajasthan block, which is of major significance to the country. At Xodus, we continue to build our experience in India and this work will be delivered with the expertise of our fully integrated team and specialised technology.”
Cairn Oil and Gas operates over a quarter of India's domestic crude oil production. The Mangala, Bhagyam and Aishwariya (MBA) are the three largest finds in Rajasthan. The oil and gas fields in the Rajasthan Block constitute Cairn's key assets in India. The Mangala field - considered to be the largest onshore hydrocarbon find in India in the last two decades - was discovered in January 2004. This was followed by the discovery of the Aishwariya and Bhagyam fields.
SIMMONS EDECO, a leading supplier of wellhead and valve maintenance, asset integrity solutions and onshore drilling services to the global oil and gas industry, announced that it has been awarded a major contract by Maersk Oil.
The contract requires SIMMONS EDECO to provide scheduled and unscheduled wellhead maintenance services for all Maersk Oil offshore wells in the Danish North Sea. In addition, SIMMONS EDECO is to refurbish valves and wellhead maintenance equipment, and manage major and consignment stock.
The five-year contract, which commenced on 1 June 2017, features three one-year options to renew. SIMMONS EDECO is supporting the contract from its new operations base in Esbjerg, Denmark, home to Maersk Oil’s Danish Business Unit.
“We are pleased to have been given the opportunity by Maersk Oil to contribute to the smooth operation of their wells in the Danish North Sea, and look forward to working with them,” said Gavin Sherwood, Business Development Manager for SIMMONS EDECO.
While SIMMONS EDECO has a long history of working in the North Sea, this is the first time the company has worked for Maersk Oil and in the Danish North Sea.
JF Mimic, part of James Fisher and Sons plc, announces it has signed an agreement to supply its specialist Mimic condition monitoring software to Stolt Tankers B.V (Stolt) - which operates the world's largest and most sophisticated ﬂeet of chemical and parcel tankers, to enhance operational safety and improve the technical reliability of its assets.
The Mimic software will be installed on Stolt’s fleet of 75 vessels, as well as onshore at its head office, to provide instant condition status alerts along with detailed efficiency monitoring, as management and control of a 21st century maritime business demands unique solutions, designed to supplement the existing ship operating procedures along with the challenges of managing a complex fleet.
Aspects of the standard Mimic condition monitoring software suite have been further developed to satisfy these demands by enhancing the software to allow raw operating data from various sources, such as the main and generator engines, cargo pumps and other auxiliary machinery, to be collected onboard and sent automatically to the Mimic application at Stolt’s head office pushing alerts to users. Further analysis can also be conducted across machinery and vessel types allowing Stolt to make informed maintenance decisions.
Andres Casanova, Stolt’s Maintenance and Reliability Manager said: “Mimic was the ideal choice for collecting, validation and the visualisation of digitalised data. The company vision is to facilitate easy access for all relevant stakeholders, both at sea and ashore. It will empower the organisation to take the lead with regards to proactive intervention of in-/de-creasing trends or exceeding threshold values. This will further enhance our operational safety and improve the technical reliability of our key assets.”
Stolt’s version of Mimic allows it to have full oversight of its vessel operations combined with a condition statement for its critical machinery and assets. The installed Mimic system provides limitless possibilities to the maintenance and operations managers to incorporate various tasks, from typical maintenance routines, calculations and reports to use when assessing individual asset, system and vessel condition; and then, uniquely, use the efficiency statement as a trigger (threshold alert) for maintenance.
The system also integrates spectrographic oil analysis results, asset condition reports, such as feed water purity and cathodic protection reports, into one easy to view dashboard from which managers can extract a wealth of real time information.
Martin Briddon, Business Development Manager of James Fisher Mimic explains: “This Mimic software suite offers all the necessary tools for robust data manipulation and in depth analysis of every maintenance task. Connecting vessels to a central hub is now achievable, leading to full control of your fleet from one system.”
The collected data is always available on the vessel’s Mimic system, as well as on the shore Mimic system. Having the option to import data in the system either manually or electronically offers flexibility, and the automated procedures help to effectively reduce the time and effort spent.
The deployment of the system was implemented remotely, and all the databases creation, specifically for each vessel, is implemented from the shore. Data is flowing in both directions between the Mimic ship and the Mimic shore system, providing a perfect communication between shore and ship side.
Shell, LLOG, Total, Marubeni, ConocoPhillips, Wild Well, Baker Hughes and Schlumberger are amongst the speakers who will be gathering at this year’s Offshore Well Intervention Conference on November 1-2 in Houston to discuss the critical challenges facing the Gulf of Mexico’s well intervention community.
As both operators and contractors continue to plot the path to increasing intervention efficiency for platform and subsea assets, the conference will help you integrate new completion designs, advanced workover technologies & a reliable late life strategy to maximize production throughout your assets’ lifecycle by discussing:
- Market Potential: Analyze GOM dynamics and activity forecasts to understand how well intervention can provide excellent ROI in the current market
- Production Enhancement: Hear how a pro-active intervention strategy coupled with new contracting models & an efficient use of proven technology can increase well stock value
- Well Design: Uncover the impact of intelligent field development on well intervention and grasp the value of a multi-disciplinary approach to platform and subsea well work
- Late Life Management: Explore how a robust well integrity and P&A strategy can help maximize production for mature assets ahead of a reliable & cost-effective abandonment
- New Technology: Discover how innovative approaches to eline, slickline and CT can help you get the most out of your GOM shallow and deepwater assets
With over 180 attendees exchanging experiences and knowledge at the DoubleTree by Hilton Greenway Plaza in Houston, the conference will provide you with all the tools you need to deploy an effective well intervention strategy.
Forum Energy Technologies, Inc. has announced a new contract that will see its market-leading pipeline and cable survey software installed on the world’s most advanced cable laying support vessel, the NKT Victoria.
Two VisualSoft Four Channel High Definition Digital Video Systems (VisualDVR MCHD) will be supplied to iSURVEY Group, a leading provider of survey and positioning services to the global oil and gas and telecommunications sectors. The first vessel installation for the newest system in the VisualSoft range, is to be utilized on the NKT Victoria in the Moray Firth.
The NKT Victoria (DNV-GL Class) is a 140m x 30m DP3 top-of-the-range diesel electric vessel with 1600m2 of deck space and two large offshore cranes. The high capacity cable lay system features a battery energy storage system to assist the cable loading in the event of failure of the shore power used during loading.
The Caithness Moray High Voltage Direct Current (HVDC) project in Northern Scotland is the largest investment in north Scotland’s electricity network since the hydro development era of the 1950s. It will see the electricity grid on either side of the Moray Firth connected via a new submarine cable capable of carrying up to 1,200 megawatts of electricity, equivalent to the electricity needs of about 2,000,000 Scottish people. This major project aims to help Scotland transition towards a low carbon economy.
Andy McAra, VisualSoft’s Product Director said: “We are very excited to release our new multi-channel high definition video solution to the market and it is great to be supplying the first of these systems to iSURVEY who we have had the pleasure of working closely with for many years.”
“It also makes us very proud to see our systems being installed on this new state of the art cable lay ship not least because her first contract will be here in Scotland.”
Kenneth Leverskjær, iSURVEY’s Project Manager said: “We have great expectations to the VisualSoft system, and are looking forward to further develop the strategic relationship with FORUM Energy Technologies as provider.”
Paul Mccormack is the Offshore Construction Shift Supervisor on the new NKT Victoria vessel. He said: “The NKT Victoria was designed and outfitted to be the very best. The latest VisualSoft HD digital video system was therefore an obvious choice to add as part of this state of the art cable lay vessel”.
The VisualSoft suite is a modular range of software applications designed specifically for use during subsea structure and pipeline inspections.
The VisualDVR MCHD system will provide the project team with up to four channels of high definition video recording complete with built in dynamic overlay and the ability to distribute live video and overlay channels without the need for additional hardware. Video files are recorded using H.264 encoding for optimum storage efficiency and playback compatibility.
In recognition of the widespread use of H.264 as a recording format within the subsea industry, VisualSoft has released an unlimited codec-free player for use within their editing suite, VisualEdit, and the viewer, VisualReview. The player has improved window handling to allow optimum use of high definition video playback.
Also within the scope of supply is VisualArchive, an application which is used to collect logged files from the video systems and copies them to pre-configured file locations on a variety of storage and backup devices such as large network storage drives which also form part of this scope.
VisualEdit Eventing will be used to provide an offline event and anomaly logging, editing and reporting capability for the project.
Refining Challenges Remain the Focus of Latin American Product Markets
Refining challenges remain the focus of Latin American product markets. Refinery crude runs in the region are expected to be 120 MB/D lower YoY in 3Q17. In Mexico, we project 3Q17 runs to fall 50 MB/D YoY, affected by outages in Salina Cruz and Cadereyta. In Brazil 3Q and 4Q17 refinery runs are set to move higher YoY. Regional gasoline demand is expected to remain soft in 2H17 while distillate demand recovers by 4Q17, driven by Brazilian consumption. Operational issues keep limiting local supply of products.
Fundamentals Warrant a Move to the Upper end of the Range
NYMEX futures continue to be whipsawed — whereby the market has materially vacillated on evolving expectations of supply/demand tightness — with swings in weather expectations heavily influencing sentiment. In addition to weather, the observable “saw-tooth” trading pattern, i.e. traversing up and down the established range, has been driven by volatile weekly EIA storage readings — as conflicting data has done little to highlight any underlying weather-adjusted trends. Altogether, with the contraction of available hydro and wind generation, gas gaining marketshare over coal in EG and the prospects of warmer weather, fundamentals point to tightening balances. Price strength will need to force some demand destruction to reach satisfactory inventory levels heading into winter.
The Curious Case of Mexican LNG Demand
Do not sleep on Mexican LNG demand just yet. PIRA’s somewhat dim view of LNG growth prospects for Mexico remain in place, as the significant expansion of U.S./Mexico pipeline capacity is underway. However, the ability to move the U.S. pipeline gas to places where LNG demand exists is not quite there and will still be a key component of gas balances during periods of maintenance in the years ahead.
Is Transmission Congestion Catching Up to Wind Buildout? Basis Risk for ERCOT and SPP Wind Farms
Transmission congestion in ERCOT and SPP, the two regions in the U.S. that have seen the greatest growth in wind generation in recent years, is resulting in steeper discounts from hub prices to the prices paid to wind generators. These discounts have been growing as installed wind capacity has increased, particularly in the ERCOT Panhandle region and the western part of SPP, impacting merchant wind farm economics, and requiring transmission upgrades to resolve. While some transmission projects are already underway, additional transmission will likely be needed to integrate the expected levels of wind in these regions.
U.S. Stock Deficit to Last Year to Continue Widening
Overall stocks drew 3.9 million barrels this past week led by a strong crude stock draw of 7.6 million barrels, 1.9 million barrels of which was in Cushing. Four week average adjusted product demand increased to 4.1%, or 780 MB/D year on year. Gasoline led the light products with stocks declining 1.6 million barrels while distillate inventories had one of their larger builds of 3.1 million barrels. For next week’s EIA data, crude stocks are forecast to decline sharply by 6.0 million barrels.
Second Quarter Global Activity Data Point to Improvements
In the U.S., retail sales for June disappointed, but consumer spending is still rebounding. Industrial production was solid, as industries in the capital-intensive sector recorded encouraging gains. The latest core inflation data remained sluggish. In the euro area, activity indicators improved in line with a pick-up in economic confidence, and second quarter GDP growth is likely to come in faster than the first quarter’s pace. China, South Korea, and Taiwan all reported a strengthening in exports, and this development bodes well for the global economic outlook.
U.S. Ethanol Prices Advance
Manufacturing margins worsened the week ending June 7 as corn costs soared. RIN prices were steady. Brazilian ethanol prices were lower while European values rose.
Record Short Covering
132.7K corn contracts. That’s the net number bought by Non-Commercials in the week immediately preceding the July WASDE. The previous week’s net of -80K turned into a net long of 50K contracts during a ~20 cent rally that peaked on reporting day (Tuesday, July 11th) in what is being called the largest short covering, volume wise, in just over two years. The immediate reaction Friday afternoon, and Sunday night in the market, was astonishment, and for bulls a fear that the dreaded Funds might actually be long at this point. Given the market reaction after the WASDE, and volume that has traded hands since then, those fears are without merit in PIRA’s opinion.
Is Gas Storage a Wind/Solar Derivative?
The intermittency of wind and solar production is developing into the balancing issue that PIRA has been promising for a long time now. It is leading to ever more volatile within-day pricing that is creating new opportunities for storage. This growing link between renewables and storage represent emerging opportunities to a storage market that has been dogged by complaints of lack of opportunity and a dearth of spreads.
Italian Prices: No Major Surprises so Far, but Signs of Underlying Strength
After a major upward move in June, PUN day ahead prices in Italy have settled slightly below expectations in July, or about €50/MWh. However, with temperatures closer to July 2016 and only 0.7 degree Celsius above normal, spark spreads have been quite robust this month, in line with a broadly bullish underlying fundamental picture.
CA Carbon up Sharply; Awaiting Cap and Trade Vote
Pricing momentum fed off the CA Supreme Court’s declining to review the legality of auctions and the emergence of market-friendly legislative proposals. The benchmark CCA contract moved above $15 in July (well above the expected 2018 auction reserve price). A stronger August auction will clear the way for unsold allowances to be re-offered starting in November. PIRA believes that a return to bank-building in the near term will limit the further upside potential for allowance pricing, even with some increased appetite to hold surplus and take on speculative length. It is still unclear whether the cap and trade extension will pass (by 2/3rd) this year/what form it will take. CARB will need to re-propose Cap and Trade Amendments if they are not adopted by the August deadline. ON linking prospects are also tentative, with elections less than a year away.
Seaborne Coal Prices Diverge, Downside Risks Looming
Coal market prices diverged this week, with CIF ARA and FOB Richards Bay prices falling W/W, while FOB Newcastle prices moved higher. The strength in FOB Newcastle prices likely stemmed from demand strength in Asia, led by China, where hot temperatures and the temporary curtailment of hydro generating capacity bolstered coal-fired generation. However, the announcement that China’s imports declined Y/Y in June illustrates that the downside risks for FOB Newcastle and the global market are becoming more prominent.
Japan Higher Runs and Higher Demand
Japanese runs rose 106 MB/D on the week, as turnarounds continue to lessen. Crude imports eased only slightly to 3.72 MMB/D, and crude stocks built again, by 5.6 million barrels. Again, finished product stocks fell modestly. Aggregate demand rebounded a strong 110 MB/D and the 4-week average trend in demand continued to move seasonally higher. Refining margins were again higher on the week and have continued to improve. Gains this week came from firmer gasoline and middle distillate cracks.
Credit Conditions Improve, Financial Stresses Remain Very Low
A very bullish week, with a big reversal in the emerging market / high yield retrenchment that had been seen the previous week. Financial stresses remain exceedingly low, though the St. Louis financial stress indicator again moved slightly higher. Commodities had a positive week, with energy being particularly strong. The dollar generally moved lower. The reflationary trade appears to have reemerged, at least this past week. The U.S. equity market hit new record highs.
The U.S. Ethanol Market Tightened as Stocks and Production Declined
U.S. ethanol inventories declined for the fourth consecutive week the week ending June 7, falling by 390 thousand barrels to a six-month low 21.2 million barrels. While total domestic output fell 7 MB/D to 1,007 MB/D, production outside of the Midwest rose 5 MB/D to a record 94 MB/D. Ethanol-blended gasoline production sunk 164 MB/D to 9,223 MB/D despite greater gasoline output.
Bean Buying Starts to Impress
An announcement Friday morning that China had purchased 1.3M MT of soybeans for the coming Marketing Year needs some context. While it is the 7th largest daily purchase in history, it’s also important to know that 2017/18 sales have been woefully slow up to this point at less than 4M MT as of yesterday. This lack of buying has less to do with price and more to do with both little concern about the size of the U.S. crop as well abundant supplies produced this year in South America.
Prices Retreat With Lack of Summer Heat
Spot on-peak energy prices were higher y/y (but lower m/m) in most East and ERCOT markets with a few notable exceptions. Loads in the East fell by 3.7% as cooling loads fell from the warmer than normal prior year. ERCOT loads were flat. Henry Hub spot prices averaged near $2.90/MMBtu in June, down ~7% from May levels. Northeast markets saw even sharper declines. In recent trading, the prompt futures contract has rebounded above $3. PIRA has revised down summer energy prices, partly in response to a lower gas price outlook but also due to lower unplanned outage rates with less reliable older coal units having been replaced by CCGTs with lower forced outage rates.
Recent EUA Price Gains Mask Long-Term Bearish Risks
PIRA expects European Carbon (EUA) prices to adjust to the downside from their current range of €5.30-5.50 during the balance of July, although lower auction volumes should still result in an EUA price bump in August. While the potential end to post-2020 market reform talks could offer a degree of support for EUAs in 3Q2017, there is also the possibility that market participants could “buy the rumor and sell the fact” of the reform package, and there appear to be few other fundamental drivers of sustained EUA price gains in the balance of 2017.
U.S. to Become Major Global Crude Oil Exporter with Infrastructure Not a Limiting Factor
The U.S. Gulf Coast will play a growing role as an oil exporter to global markets and will become one of the largest exporters in the world. Its infrastructure will be ready to supply increasing volumes to a thirsty global market. PIRA forecasts U.S. crude oil exports will grow to 2.25 MMB/D by 2020, a four-fold increase from 2016. This growth will be driven primarily by rising light sweet crude supplies from shale production. Proposed capital projects are pointing toward Corpus Christi becoming the primary Gulf Coast export hub once they alleviate logistical constraints and provide access to Permian supplies.
Global Equities Post New Record Highs
Many global equity markets hit new record highs this past week, including the S&P 500. In the U.S., the growth indicator posted a strong gain in momentum. Technology, energy, and materials all exhibited strong performances. Banking, however, lagged and declined. Internationally, the tracking indices generally did even better than the U.S. performance with Latin America, China, emerging Asia, emerging markets all posting robust gains.
The information above is part of PIRA Energy Group's weekly Energy Market Recap - which alerts readers to PIRA’s current analysis of energy markets around the world as well as the key economic and political factors driving those markets.
In 2015, the Department of Energy’s Wind Vision Report projected that the US offshore wind industry could support investment to reach a cumulative capacity of 3 GW by 2020, 22 GW by 2030 and 86 GW by 2050. These targets do look wildly unrealistic, but the prospects for growth in offshore wind still look strong even under a Trump presidency.
The US saw its first commercial offshore wind farm installed off Rhode Island at the end of 2016. Although small in size (30 MW at full capacity) Deepwater Wind’s Rhode Island marks a milestone for the US renewables sector. This is the country’s first operational offshore wind farm, which could lay the foundation for several developments off the US coast over the next decade.
Westwood Global Energy Group’s (WGEG’s) World Offshore Wind Market Forecast 2017-2026 paints an encouraging picture for the US offshore wind sector over the next decade. Cumulative capacity is set to grow from 30 MW in 2016 to 2.5 GW by 2026, with an additional 1 GW of capacity from projects which have not yet passed conceptual phases, assuming an offshore wind target of 5GW by 2030.
USA Cumulative Capacity by Current Project Status, 2016-2026
US offshore wind expenditure is forecast to total $28bn between 2017 and 2026, with a 39% year-on-year growth. Hardware Capex is expected to amount to €19.1bn, accounting for 68% of total spend, followed by installation at €6.2bn (22%) and planning and development at €2.9bn (10%). The US total population of operational turbines is expected to grow from 6 in 2016 to 580 by 2026.
Since Rhode Island, Deepwater Wind has obtained a permission to build the 90 MW Deepwater One wind farm off New York. Statoil will also be exploring the potential to host over 1 GW offshore New York. Other encouraging signs include the first US auction under Trump, which resulted in a winning bid of nearly $9.1m from Avangrid Renewables, for the 1.5 GW Kitty Hawk project lease, and the award of offshore wind renewable credits by the Maryland Public Service Commission in May 2017.
Despite president Trump’s pro-oil and gas stance and his decision to leave the Paris Climate Accord, there are some positive signs that US offshore wind is gaining momentum. More importantly, as each state has its own renewable electricity mandates, the withdrawal from the Paris Climate Accord is likely to affect emission targets at a federal level only. It remains to be seen the extent to which President Trump will be able to influence individual states’ renewable policies.
Marina Ivanova, Analyst, Westwood Energy
Talos Energy LLC ("Talos" or the "Company") as operator, together with its joint venture partners Sierra Oil and Gas S. de R.L de C.V. ("Sierra") and Premier Oil Plc ("Premier"), is pleased to announce that the Zama-1 exploration well, offshore Mexico, has discovered oil. Talos holds a 35% participation interest with Sierra and Premier holding 40% and 25% participation interests, respectively.
The Zama-1 well is the first offshore exploration well drilled by the private sector in Mexico's history. The well, located in 546 feet (166 meters) of water and approximately 37 miles (60 kilometers) from the Port of Dos Bocas, has reached an initial shallow target vertical depth of approximately 11,100 feet (3,383 meters).
Preliminary analysis indicates:
- A contiguous gross oil bearing interval of over 1,100 feet (335 meters), with 558-656 feet (170-200 meters) of net oil pay in Upper Miocene sandstones with no water contact
- Initial gross original oil in place estimates for the Zama-1 well range from 1.4 to 2.0 billion barrels, exceeding pre-drill estimates, some of which could extend into a neighboring block
- Initial tests of hydrocarbon samples recovered to the surface contain light oil, with API gravities between 28° and 30° and some associated gas
"This is both a historic and significant discovery, and we could not be more proud of the highly skilled personnel from Mexico and the US who have been working together in a safe and efficient manner to make it a reality," said Tim Duncan, President and Chief Executive Officer. "We believe this discovery represents exactly what the energy reforms intended to deliver: new capital, new participants and a spirit of ingenuity that leads to local jobs and government revenues for Mexico.We are eager to begin appraising this discovery and drilling more unique opportunities. The future is bright for offshore Mexico for years to come."
"This success is the culmination of a tremendous amount of work by our technical and operations teams in concert with our consortium partners Sierra and Premier," Duncan continued. "The team deserves a great deal of credit for their conviction in this opportunity and their leadership in making Talos the first private sector operator to receive acreage and drill a successful offshore exploration well in Mexico following the landmark energy reforms of 2014."
The well spud May 21, 2017 utilizing the Ensco 8503, a moored floating drilling rig. The Company is currently setting a liner to protect the discovered reservoirs prior to drilling deeper exploratory objectives to a total vertical depth of approximately 14,000 feet (4,267 meters). There are no plans for immediate well testing. Further evaluation will be required to calibrate the well with the existing reprocessed seismic to determine future plans and optimal follow up locations to define the extent of the discovered resource.
During 2015, the Company, together with its consortium partners Sierra and Premier (the "Consortium"), executed two production sharing contracts ("PSCs") with Mexico's upstream regulator, the National Hydrocarbons Commission, for Block 2 and Block 7. The PSCs were awarded to the Consortium during the first tender of Mexico's oil and natural gas fields in over 80 years. Block 2 and Block 7 are located in the
Sureste Basin, a prolific proven hydrocarbon province, in the shallow waters off the coast of Mexico's Veracruz and Tabasco states, respectively. Block 2 and Block 7 contain approximately 162,904 gross acres with numerous high impact prospects in well-established and emerging plays.
ABOUT TALOS ENERGY LLC
Talos is a technically driven independent exploration and production company focused on the exploration, development and acquisition of oil and natural gas properties primarily in the Gulf of Mexico Developed Deepwater and Shelf and on the Texas and Louisiana Gulf Coast, with year-end net proved reserves of over 100 million BOE and production of approximately 30,000 BOE/day net to the Company's interest. During 2015, we leveraged our technical and operational expertise in the Gulf of Mexico and expanded our acreage position into two shallow water exploration blocks off the coast of Mexico.
Otto Energy Limited (ASX:OEL) (‘Otto’ or the ‘Company’) announces it has farmed into the South Timbalier 224 (‘ST 224’) lease in the Gulf Of Mexico shelf, for a 25% working interest. ST 224 contains a large, amplitude supported, high CGR, gas condensate exploration prospect located in the prolific Bul. 1 trend which is expected to be drilled in Q4 2017. The prospect is surrounded by analogue high CGR discoveries which present a similar amplitude expression on 3D seismic data making this a very attractive low risk exploration opportunity. Otto intends to release further information on the prospect, including prospect volumetrics, closer to the drilling date. A summary of lease working interests can be seen in the table below.
|Company||Working Interest (%)|
|W&T Offshore (Operator)||39%|
|Other Private US Company||25%|
The prospect sits in approximately 170 feet of water and has a relatively shallow target depth. Several existing production platforms fall within tie-back distance of the proposed well, enhancing economics and making development of any discovered hydrocarbons both quick and cost effective. Additional follow up drilling potential exists on the lease.
Under the terms of the participation agreement, Otto will be required to fund 25% of the initial test well in the ST 224 lease (up to casing point) to earn a 25% working interest in the ST 224 lease. The financial commitment is currently estimated at US$2.7 MM (Otto share of dry hole costs), including funds to evaluate the well using wireline techniques and in a failure case to P&A the location. Otto will also pay US$81,250 in back costs.
There is no promote on the exploration well payable by Otto. Should a development proceed at ST 224, Houston Energy will be entitled to a backin after payout at the point where Otto recovers its share of all exploration and development expenditures from its share of net project revenues. Otto’s Working Interest would be reduced by 10% at this point in time from 25% down to 22.5%.
Otto’s Managing Director, Matthew Allen, commented: “We are excited to secure a 25% interest in the highly prospective ST 224 lease partnering with an experienced Gulf of Mexico operator in W&T Offshore and Houston Energy a very successful Gulf of Mexico prospect generator. This complements our existing SM 71 development in the Gulf of Mexico which is due to commence production in late 2017. The farm in structure with no promote on the initial test well, and a back in after payout only in the success case after all costs have been recovered minimizes up front entry costs. In the success case, pre-drill economics support a very robust development project at current oil price which W&T Offshore have indicated could have first production by end 2018. Otto hopes this is the start of a fruitful working relationship with these companies in the Gulf of Mexico.”
SCHEDULE 1 – BACKGROUND ON ST 224 PROSPECT FARM IN
LOUISIANA/GULF OF MEXICO – SOUTH TIMBALIER 224
Location: Offshore Gulf of Mexico
Gross Area: 20.23 km2 (5000 acres)
Otto’s Initial Working Interest: 25%
Water Depth: 170 feet
Prospect Target Depth: 10,500 feet (TVD)
Through the drilling of an exploration well in ST 224, Otto will earn a 25% Working Interest (equal to a 19.5625% Net Revenue Interest) in the license in exchange for paying 25% of the initial test well costs to casing point, currently estimated at US$2.7 MM (Otto share) dry hole costs (including funds to evaluate the well using wireline techniques and in a failure case to P&A the location). In addition, Otto will be required to fund US$81,250 in back costs.
Houston Energy will be entitled to a back in after payout, when Otto recovers from its net revenues from ST 224, all development and exploration expenditures (including back costs) spent on ST 224.
Otto’s interests before and after payout can be seen in the table below.
|Before Payout||After Payout|
|Working||Net Revenue||Working||Net Revenue|
BOEM announces that they have completed an analysis of their royalty rates and have decided to set the royalty rate at 12.5 percent for leases located in water depths less than 200 meters in the proposed Gulf of Mexico (GOM) Sale 249. This is lower than the proposed 18.75 percent royalty rate for shallow water leases that we published in the Proposed Notice of Sale, and is consistent with the Federal onshore oil and gas lease royalty rate of 12.5 percent. The purpose of this change is to adjust the royalty rate to reflect recent market conditions, thereby encouraging competition and continuing to receive a fair and equitable return on oil and gas resources. The royalty rate in 200 meters of water and deeper will remain at 18.75 percent as in the Proposed Notice of Sale.
BOEM has made this decision after careful consideration of market conditions, available resources, leasing, drilling, and production trends, along with comparable international fiscal systems. In particular, hydrocarbon price conditions and the marginal nature of remaining GOM shelf resources suggest a royalty rate reduction is an appropriate and timely action. The shallow water royalty rate reduction targets the GOM shelf where exploration, development, and production are in decline and where critical infrastructure already exists.
If BOEM moves forward with the sale, the royalty rates and other lease terms related to GOM Sale 249 will be formally announced in the Final Notice of Sale at least 30 days prior to the sale date. The sale date is currently scheduled for August 16, 2017. BOEM is sending this Note to Stakeholders informing you of this change ahead of the Final Notice of Sale because it was made after the Proposed Notice of Sale for GOM Sale 249 (published in March of this year).
GOM Sale 249 is the first scheduled lease sale in the 2017-2022 Outer Continental Shelf Oil and Gas Leasing Program, and is also the first scheduled Gulf of Mexico region-wide sale that encompasses all available acreage in the Western, Central, and Eastern planning areas. The unleased blocks are located between 3 nautical miles offshore out to the outer limit of the United States' jurisdiction over the Outer Continental Shelf (OCS) in water depths ranging from 3 meters to more than 3,400 meters.
BOEM also announces that they are analyzing a price-based royalty system and will be engaging stakeholders on this concept later this year. BOEM's concept of a price-based royalty system would provide an incentive to lessees through lower royalty rates in times of lower oil prices, while also ensuring the Federal government receives a greater return for Outer Continental Shelf resources when prices are high. A price-based royalty system will not be in place for GOM Sale 249. BOEM expects to provide more information and provide opportunity for stakeholder input in the coming months.