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.
BHP Billiton has announced that it submitted the winning bid to acquire a 60 per cent participating interest in and operatorship of blocks AE-0092 and AE-0093 containing the Trion discovery located in the deep-water Gulf of Mexico offshore Mexico. PEMEX Exploration & Production Mexico (Pemex) will retain a 40 per cent interest in the blocks. Pemex estimates the gross recoverable resource to be 485 MMboe. Subject to satisfaction of conditions (including the obtaining of government approvals), it is anticipated that the relevant agreements would be finalized and signed within 90 days.
BHP Billiton’s bid for Trion includes an upfront cash payment of US$62.4 million and a commitment to a Minimum Work Program (estimated to be up to a maximum of US$320 million).
Should BHP Billiton and Pemex agree to progress the project beyond the Minimum Work Program, BHP Billiton would be required to invest the remainder of the US$570 million Minimum Work Contribution (which includes the Minimum Work Program spend) and a US$624 million cash contribution (which comprises the upfront cash payment of US$62.4 million already paid and the balance of US$561.6 million as a future carry for Pemex). BHP Billiton’s bid also includes a commitment to an additional royalty of 4%.
Steve Pastor, BHP Billiton President Operations Petroleum, said “We see attractive potential in Trion and the Perdido trend, and we are pleased to have the opportunity to further appraise and potentially develop this prospective frontier area of the deep-water Gulf of Mexico.”
“This opportunity aligns with our strategy of owning and operating Tier-1 assets and provides an opportunity for BHP Billiton to leverage its industry leading deep-water drilling, development and operational expertise to create value in Mexico.”
BP announced, that drilling has commenced on a potential carboniferous gas play in southern North Sea block 43/26a that, if successful, could open up a new phase of development in the region.
The well, being drilled with partners Perenco and Premier, will test the potential of a deep carboniferous age horizon several hundred meters beneath the mature reservoirs produced by the Ravenspurn ST2 platform.
Photo courtesy: BP
Mark Thomas, BP North Sea regional president, commented: “This play warrants further exploration as we know the reservoir sands exist. What we don’t know is whether, if gas is found, long-term production can be proven economic from this deeply buried reservoir horizon. We’re looking forward to working with Perenco and Premier to test this concept and better understand its potential.”
During the drilling and testing phase, Perenco - as operator of the existing producing Ravenspurn field - will act as substitute operator on behalf of BP and the other license owners.
BP holds an 85% equity stake in the prospect alongside license partners Perenco (10%) and Premier (5%).
Bibby Offshore, a leading subsea services provider to the oil and gas industry, announced that it has secured a significant contract with Shell.
The campaign, due to commence in Q1 2017, will see Bibby Offshore provide engineering and subsea construction activities in the Gannet G field in the Central North Sea.
Under the agreement, Bibby Offshore will utilise its multipurpose dive support and offshore construction vessel - Bibby Polaris - and its integral 1000 tonne basket carousel to lay flexible pipe systems in water depths of approximately 95m.
Bibby Offshore Chief Executive, Howard Woodcock
The company has also collaborated with a third party operator who will carry out trenching operations after the initial workscope is complete.
In early 2016, Bibby Offshore provided construction and inspection services for Shell on assets in the Corrib Natural Gas field in the North Atlantic Ocean, successfully completing two significant contracts.
Howard Woodcock, chief executive of Bibby Offshore said: “Securing this project was a direct result of our established and successful track record with Shell. This contract will further strengthen our relationship, and highlights Bibby Offshore’s ability to consistently and successfully deliver on complex and challenging projects.”
Marsol International, a UAE-based global marine solutions provider focused on the offshore oil terminal market and related infrastructure, has announced the launch of its new office, Marsol International Abu Dhabi.
The facility strengthens Marsol’s presence in the UAE region and increases the company’s capabilities for directly servicing Abu Dhabi-based clients.
Marsol has already undertaken several projects from the facility, including offshore hose studies involving modelling, inspection and repair operations, Emergency Pipeline Repair Service (EPRS) support and tanker terminal assessments for major companies in the area, as well as undertaking the Oman Oil Company Exploration & Production LLC’s first two shipments of crude oil from the Musandam gas plant.
Mike Young, Director of Marsol International, said: “It’s vital that we can provide the best possible service to our clients and our new Abu Dhabi facility ensures that we can effectively and efficiently complete projects in this region. The new facility has also led to the recruitment of two new team members who are ideally placed to provide on-the-ground support to our clients.
“We have already undertaken a number of significant projects which utilised our specialist, integrity management driven, holistic approach to operational and IRM solutions and we look forward to working closely with operators and service companies based in Abu Dhabi as we continue to expand our onshore and offshore operations.”
Since 2005, based on experience gained over 47 years, Marsol International has provided operational engineering and management solutions to clients, consultants and EPC contractors for new offshore terminal facilities, and operational integrity management and IRM services of existing facilities to offshore terminal owners and operators.
As a result of multiple contract wins in 2016, independent subsea Remotely Operated Vehicle (ROV) service provider, ROVOP, has recovered strongly from the downturn in the oil and gas industry.
The company enjoyed a record period in the second half of its financial year with sales of almost £10million and EBITDA of £3.5m for the six months to September 2016, an increase of 14% and 27% respectively over the same period in 2015.
It also welcomed 15 new customers, spanning ten countries, to its high-profile global portfolio of clients and expanded its fleet with an electric work class ROV, the Seaeye Leopard, the most powerful vehicle for its size in the world.
ROVOP deploys an ROV off the coast of Germany. Photo credit: ROVOP
Earlier this year ROVOP was named as one of the London Stock Exchange’s 1000 Companies to Inspire Britain. The report was a celebration of the UK’s fastest-growing and most dynamic small and medium sized businesses.
To be included in the list, companies needed to show consistent revenue growth over a minimum of three years, significantly outperforming their industry peers.
Chief Executive, Steven Gray, said: “Our last financial year was very much in two halves. The bankruptcy of one of our major clients in 2015, Ceona, presented a significant challenge that came as the falling oil price bit hard. But I am delighted with the way our team responded, delivering a strong rebound in activity and financial results to achieve a doubling of revenue from the first half of our financial year to the second.
“We have achieved several significant milestones this year. These include our first project in South East Asia, the successful completion of a multi-year North Sea decommissioning project, the deepest unexploded ordnance survey and relocation project ever undertaken globally, the first installation of commercial scale tidal energy turbines in Scotland and securing a second world war submarine that posed a significant environmental risk. I am delighted with the success of the projects and the momentum we have managed to build in a challenging landscape.
“The market now clearly recognizes that current generation ROVs lower cost and the importance of the high quality personnel employed by ROVOP and trained in our in-house academy.”
The company has also announced the appointment of Lee Shanks as Business Development Manager. Lee has joined ROVOP in its Aberdeen office and brings extensive subsea sector experience to drive further business growth.
Commercial director, Euan Tait, explained the addition of Mr. Shanks to the team will be key:
“Lee has exceptional experience both in technical and customer facing roles. Appointing him as Business Development Manager is an important part of our plans to maintain close relationships with our clients as well as further strengthening our position with new customers in new territories.
“The market remains challenging but our ability to lower costs, while using the best equipment and personnel on the market, means we continue to enjoy regular successes. This appointment will further drive our business development and those successes into the New Year.”
Hyperdynamics Corporation (OTCQX: HDYN) announces that it has signed a definitive drilling services contract with a subsidiary of Pacific Drilling SA to engage the Pacific Bora drillship to begin a drilling campaign offshore the Republic of Guinea in the second calendar quarter of 2017.
"This contract underscores our commitment to drilling our next exploration well offshore the Republic of Guinea next year," said Ray Leonard, Hyperdynamics President and Chief Executive Officer. "Since the signing of a preliminary Letter of Award with Pacific Drilling a month ago, we have also achieved several other crucial milestones that will enable us to begin drilling the Fatala-1 prospect this spring.
"Long-lead time equipment and materials that are being turned over to Hyperdynamics by former operator Tullow Oil are currently being inspected at a storage yard in Ghana before shipment to Guinea. We are in the process of tendering for the major services that will be needed for our drilling operations as well as for support services such as boat and helicopter transportation.
"We are continuing to hold discussions with prospective working interest partners, including major multinational energy companies and independents, to share project-related costs and risks and to enhance project technical competencies. We are also exploring options to raise equity through a share offering," Leonard said.
The Pacific Bora is currently located in West Africa, has just finished a contract for a major American exploration and production company. The drillship is expected to arrive shortly before the target spud date for the Fatala-1 well. Hyperdynamics' contract with Pacific Drilling enables us to include as many as three additional wells under the same favorable terms and conditions.
Hyperdynamics is an emerging independent oil and gas exploration company that is exploring for oil and gas offshore the Republic of Guinea in West Africa. To find out more, visit our website.
With OPEC Delivering on Cuts, Prices to Move HigherReflation backdrop together with OPEC cuts are very bullish for oil prices. OPEC cuts and the momentum of supply losses will make it difficult for the supply chain to turnaround fast enough to avoid very low oil inventories in second half 2017. Geopolitical risks suggest downside to PIRA’s supply forecast. Refining margins to stay relatively healthy with help from increased light product pull by Latin America. Global bunker spec changes will be a game changer in three years, but will affect investment plans long before then.
Cash prices this month have been whipsawed by exaggerated NYMEX volatility, with abnormally mild weather the driving force. Yet, colder forecast changes on the horizon have restored a bid under cash prices, with further price appreciation waiting on December storage withdrawals.
There’s historical context attached to every comment in today’s report, and here’s one more. An old CBOT saying goes “Bulls feast on Thanksgiving, Bears feast on Christmas”. This year the bulls had a good Turkey Run in corn and beans while wheat lagged, setting up the possibility of the old adage coming true again.
Prices were supported by robust exports resulting in a large drop in stockpile. Manufacturing margins increased as product prices rose faster than corn costs. The EPA set the final biofuels mandates and standards for 2017. RIN prices soared.
The November U.S. payroll report was constructive for the economic outlook, as most industries reported solid job growth. A separate household survey of the labor market, however, was potentially worrisome: the unemployment rate fell sharply, as a result of unemployed people dropping out of the labor force in significant numbers. How Fed policymakers assess this development will have a large bearing on monetary policy in the coming periods. In emerging economies, India reported solid GDP growth for the third quarter. Brazil’s activity data disappointed. China’s industrial confidence indicators continued to improve.
Coal pricing was mixed this week, with the bullish rally that prevailed last week extended into Monday/Tuesday, although prices then moved lower over the balance of the week. The news that several major Chinese coal producers were signing term deals with consumers at the coal trade fair in Hebei this week gave the market a bearish push. Additionally, the chairman of the China National Coal Association stated this week that China's coal prices will stabilize in the 550-600 yuan/mt range ($80-$87/mt), further underscoring the push from China to deflate high coal prices. 1Q17 FOB Newcastle prices declined by the largest extent, falling by over $2.00/mt while API#2 and API#4 prices managed slight week-on-week increases despite downward pressure over the second half of the week. Looking forward, coal demand is on firm fundamental footing with recent cold weather boosting electricity demand and with hydro generation likely to remain soft into 1Q17. Additionally, seasonal risks to coal production and transportation have not yet peaked, which should prevent much further price erosion and may foster a pricing rebound.
The Obama Administration is finalizing regulations, despite threats of Congressional Review Act repeal. EPA continues to work on the Clean Power Plan’s FIP and the model trading rules. Amendments to the Regional Haze Rule, are being finalized. Final GHG emission standards for heavy-duty vehicles were published, along with the CSAPR rule impacting power plant NOx emissions. RFS standards for 2017 and 2018 have been finalized but not yet published. EPA released a proposed determination not to revise CAFE standards for 2022-2025. DOI regulation of venting and flaring on federal lands has been published. Final rules after May 30, 2016, may fall under CRA review. Since mid-May, 49 "major" rules and 973 non-major rules have been received by GAO.
Downside risks noted last month came to fruition in November, but they quickly dissipated as gas prices reversed course during the second half of the month and precipitation declined to below-normal levels. Precipitation above The Dalles averaged 56% of normal through November 25; the water year to date remains above normal, but runoff projections have been trimmed. Although implied heat rates remain down year-on-year through the first half of 2017 as the market digests solar capacity additions, higher gas prices, and increases in hydro supply (even after the markdown), we expect a rebound during the second half of the year.
Prices will move higher with ongoing rebalancing. Demand growth is healthy. Relatively firm gasoline cracks support margins. Light product stock levels are still high but declining. Product price spreads shift from favoring gasoline toward distillate but gasoline comes back quickly in 2017. Global bunker sulfur limits drop to 0.5%beginning in 2020. No near term impact on prompt prices, but it will affect forward curves and investment decisions; European sour crude refiners will need to adapt.
European gas markets are demand focused at the moment — focusing on increasing gas-to-power demand and cooler-than-normal temperatures. Power demand across Central and Western Europe is up 70 mmcm/d year-on-year; however, the big shift, really happened in September. Much of the current increases in demand are seasonal. At the same time, heating demand for residential and commercial sectors is seeing the first higher-than-normal numbers in consecutive months for six years. The last time we saw this sort of continued cold was in 2010, which coincidentally was also a La Nina year.
Global equity markets posted a degree of consolidation from record highs. In the U.S., among the key tracking indices, energy performed the best on the back of higher oil prices in the wake of the OPEC agreement to cut output. Banking and materials also outperformed, while housing was the weakest performer. Internationally, the tracking indices were mostly lower, with Latin American displaying the greatest retrenchment. Japan was modestly higher.
U.S. LPG prices mostly rose in line with the broader energy markets. January Mt Belvieu propane prices gained 7.4¢ to settle at 62¢/gal Friday, the highest level yet in 2016. Similarly, n-butane at the market center gained 12.7% to 83.6¢. Cash isobutane continued to rally last week, encouraged higher by the latest EIA inventories, which for September put iC4 stocks at 8.3 MMB vs 9.5 in the year ago period. Isobutane prices ended the week at a strong 19¢ premium to normal. Ethane prices rose faster than Henry Hub natural gas, and thus C2’s premium to gas in BTU terms gained to 26¢ from 12¢ a week ago.
The week ending November 25, U.S. ethanol stocks dropped to the lowest level since October 2015. Ethanol production decreased by 2 MB/D to a still-high 1,012 MB/D. Ethanol-blended gasoline manufacture fell to 8,998 MB/D, dipping below 9 MMB/D for only the second time over the last six months.
4Q16 Latin American gasoline demand is set to decrease by ~10 MB/D year-on-year while diesel consumption declines by ~50 MB/D year-on-year. 4Q16 Latin American crude runs are forecast to fall 335 MB/D year-on-year. Petrobras’ Brazilian automotive fuel pricing policy changed and will drive domestic ex-refinery prices to converge towards their respective opportunity costs. In the U.S., gasoline cracks have weakened but remain healthy for the season. Distillate cracks remain relatively soft but should rise in the short term as the heating season progresses.
The OPEC production cut has sent Brent crude screaming up more than $11/bbl ($1.88/MMBtu) higher than recent lows. This increase will have strong implications for gas flows in the coming months due to the relative value of spot versus oil-indexed gas. Recently, the latter had been selling well under hub pricing in certain markets, enjoying a significant price advantage for many buyers — something that has never in modern times been consistently enjoyed by major supply contract holders. This advantage is withering quickly and the price response to the OPEC meeting will extend the effect well into 2017.
French nuclear availability for December has been further downgraded. While the outlook for nuclear in January and February 2017 is very similar to our prior monthly report, we still see risks of further outage extensions. This is to say that France will remain heavily dependent on imports to balance the system at on-peak hours during December and, almost certainly, January. The partial cut-off of France-U.K. interconnector availability through February/March enhances the risks of exceptional measures and/or systemic balancing failures on both sides. As French and U.K. prices will remain even more weather-driven, German peak prices are already factoring in a bullish market context, with price upsides only emerging under a scenario of poor wind availability for extended periods.
The rally in coal pricing continued into the early stages of November, although on news of supply contracts being signed in China, pricing dropped significantly. Prices have recovered in recent days, although remain well below last month’s peaks. Sort-term fundamentals remain strong, particularly with asymmetrical pricing risks to the upside from the potential of winter weather boosting demand and curtailing supply (production and transportation). PIRA remains bullish into 2017, although we note that some of the frictional factors boosting prices (misaligned supply/demand domestically in China) will evaporate over 2017, and 2018 will be a more bearish picture, particularly if the supply side cannot hold discipline.
This week saw the European Commission publish the Winter Package, a set of proposals that aims at delivering on the global climate deal reached with the 2015 Paris Agreement. The package details the vision of the EC regarding the decarbonization of the energy sector with the integration of renewables, outlines energy efficiency targets by 2030 and 2050, and discusses the potential effects on the security of supply in the transition phase. While these may be seen as long-term issues, nevertheless we thought the documents offer some important medium-term implications for coal and other higher emitting capacities.
This week’s OPEC meeting reminds us that while Saudi Arabia does not control the price of global crude markets, its underlying influence on the price of Brent and WTI is without question. And so it goes with Qatar and its influence on LNG prices. Qatari prices do not play an active role in the price of NBP or JKM, but without question, Qatari prices reflect the state of the market.
The equity market eased slightly off its record close from last Friday. Volatility increased, and debt performance weakened. All of the adjustments are seen as within the bounds of consolidation. Fears of the outcome of the Italian referendum over the past weekend did not appear to have rattled the markets too badly this past week. The big winner of the week was energy, due to the OPEC agreement to cut output and the subsequent rise in oil prices.
Total commercial stocks only added 0.5 million barrels for the latest week. Crude stocks drew by 0.9 million barrels as crude imports were flat. The four major products experienced a 7.6 million barrel stock build, led by distillate’s nearly 5 million barrel increase. The major product build was partly offset by the large declines in NGL storage. The net total product inventory gain was 1.4 million barrels. Next week’s EIA data is expected to see another crude stock draw. The three major light products are anticipated to build by 5.8 million barrels, led by a build in gasoline stocks.
A rather abrupt change in the weather forecast has unleashed heavy natural gas futures buying, with the current week on track to add yet another ~0.25¢ to the Jan 2016 contract. Since establishing a near-term low of $2.88/MMBtu back on November 17, the Jan 2016 contract has since recovered ~0.60¢ to ~$3.50/MMBtu as the forecast (initially heralding a warmer-than-normal start to December) has given way to a much cooler outlook. Yet, with the front of the curve now closing in on the calendar-year high established mid-October, there is a risk that these newly minted wagers on winter-time rebalancing could likewise prove premature.
Pakistan’s Economic Coordination Committee (ECC) of the cabinet approved a nearly 33% cut in prices of natural gas, the first such slash this year, for the industrial sector. A statement said that Ishaq Dar, minister for finance, chaired the ECC meeting, which “… approved reduction of gas price for industry. In accordance with Fertilizer Policy 2001, the industrial sector's gas sale price will also be applicable to the fertilizer sector and only for fuel and not feed stock,” it added.
EIA data estimates for electric power sector stockpiles as of end-September came in at 158.2 MMst, slightly higher than PIRA expected, but 4.4 MMst lower than August and 4.5 MMst lower than last September. As stocks generally build in September due to shoulder season weather, news of a September drawdown is positive for stockpile normalization. We maintain that U.S. power sector coal burn will rise year-on-year steadily through June 2017, and we will see stockpiles descend further toward normal levels.
Crude runs rose with turnarounds winding down. Crude imports fell back such that crude stocks corrected back down 2.4 MMBbls. Finished products built 1.1 MMBbls off their cyclical low. Compared to year-ago, the deficits on crude, finished products and total commercial stocks narrowed a bit. Both gasoline and gasoil stocks built, while the draw rate on kerosene stocks was cut from 72 MB/D to 31 MB/D. Margins and cracks eased slightly on the week, but remain statistically very good and still holding above averages seen in September and October.
PIRA assigns coefficients to measure the effect of Heating Degree Days on distillate demand in many regions of the world. There are, however, no comparable coefficients for residential demand only, nor are there any estimates of heating oil inventories held by U.S. households as is the case with German tertiary gasoil inventories. This note estimates HDD coefficients for U.S. residential consumers and derives the profile of additions and withdrawals from home heating oil storage tanks.
November weather for the three major OECD markets turned out to be 5% colder than the 10-year normal and the resulting oil-heat demand effects were 86 MB/D above normal. On a 30-year normal basis, the markets were 4% warmer.
EIA recently released their September oil balances. Domestic crude supply, which is domestic crude production plus the balancing item, fell sharply, month-on-month by -470 MB/D, the largest monthly drop since supply peaked in April 2015. The year-on-year decline accelerated from -500 MB/D in August to -950 MB/D in September, and steeper than the previous steepest decline of -932 MB/D seen in April 2016. The September declines, both month-on-month and year-on-year, were about 50 MB/D steeper than PIRA's initial estimates.
EIA recently released its final monthly September 2016 (PSM) U.S. oil supply/demand data. September 2016 demand came in at 19.864 MMB/D. Overall demand was revised lower by only 92 MB/D, compared to the weeklies. Total product demand increased 2.3% versus year-ago or 450 MB/D, compared to the September 2015 PSA data, doubling the growth seen in August. End-September total commercial stocks stood at 1,352.5 MMBbls. Compared to final September 2015 PSA data, total commercial stocks are higher than year-ago by 76.3 MMBbls, versus an excess of 101.2 MMBbls seen at end-August and a 123.2 MMBbls excess seen at end-July.
Chinese refiners have been exporting increasing volumes of key refined products such as gasoline, jet fuel and gasoil/diesel since 2012. However, it is important to note that Chinese refiners have also been importing increasing amounts of mixed aromatics and light cycle oil over the past two years, which are generally used as blending components for gasoline and gasoil/diesel, respectively. Taking these blending components into consideration, the product balance for total gasoline is more neutral (perhaps at times even bullish), and the product balance for total gasoil/diesel is only moderately bearish. PIRA expects China’s net exports of gasoil, jet fuel and gasoline (excluding blending components) to increase by another 10% in 2017.
Saudi Arabia's formula prices for January were just released. The adjustments were in alignment with what the pricing drivers would dictate. This means Saudi will resort to cutting allocations to refiners and let the market tighten that way, as opposed to initially tightening differentials and reducing the competitive attractiveness of Saudi crude. Consequently, Saudi crude remains priced competitively from an economic standpoint, but less avails will be released to the market as refiner's allocations will fall short of their nominations. Specifically, Asian terms were made more generous in line with the change in Dubai structure, while pricing into Northwest Europe was tightened in line with the narrower discount on Urals vs. Dated Brent.
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.
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.
CGG announces the delivery of near real-time imaging results for a 4,200 sq km BroadSeis 3D marine seismic survey acquired offshore Morocco. CGG delivered the very-fast-track (VFT) RTM PSDM volume to the client only 4 days after the last shot.
The 4,200 sq km BroadSeis 3D seismic survey offshore Morocco was acquired by the Geo Caspian.
This technical feat crowned an excellent operational performance by the crew of the CGG Geo Caspian who worked in a safe, collaborative and effective partnership with the client to complete the program ahead of schedule.
Jean-Georges Malcor, CEO, CGG, said: “This exceptional achievement surpasses our record last year when we delivered 1,700 sq km of fast-track depth imaging data just 9 days after acquisition for another survey offshore Morocco for the same client. It reflects the dedication of our offshore and onshore experts to go the extra mile to deliver results that continue to exceed our clients’ expectations.”
Subsea Integration Alliance has announced the industry’s first deepwater integrated subsea engineering, procurement, construction, installation and commissioning (EPCIC) multiphase boosting system award. This award, by Murphy Exploration & Production Company–USA, a subsidiary of Murphy Oil Corporation (NYSE: MUR), is for the industry’s longest deepwater subsea multiphase boosting tieback.
Building on a track record of numerous engineering studies, this is the first EPCIC project award for Subsea Integration Alliance, which was formed July 2015 between OneSubsea, Schlumberger, and Subsea 7. The scope of the contract calls for the supply and installation of a subsea multiphase boosting system for the Dalmatian Field in the Gulf of Mexico. This includes topside and subsea controls, as well as a 35 km integrated power and control umbilical. The alliance enables a turnkey integrated project from design through supply, installation and commissioning.
“OneSubsea has a strong track record of innovation, including world-leading experience in subsea multiphase boosting systems. More than 35 projects, including some 100 subsea pumps, have been delivered since 1994,” said Mike Garding, president, OneSubsea, Schlumberger. “This fit-for-purpose subsea boosting technology will improve Murphy E&P’s ultimate recovery through a cost-effective, record tieback. The innovative business model of the alliance further contributes to greater certainty of cost and return on investment.”
Subsea 7’s Chief Executive Officer, Jean Cahuzac, added, “This contract recognizes our successful alliance model that brings together Subsea 7’s SURF technology and extensive track record in delivery of large-scale complex EPCIC projects, with OneSubsea’s reservoir and subsea production, and processing systems technologies. Our alliance presents Murphy E&P with many opportunities to improve their field economics, and reduces complexity, cost and risk to achieve production objectives safely, on time and within challenging cost targets.”
Through the alliance, the organizations will work closely together across their project management teams, sharing knowledge and best practices to identify opportunities for continuous improvement while providing seamless project execution. Murphy E&P will benefit from the removal of interface and design risks associated with conventional subsea solutions. Offshore installation activities are scheduled for 2018.
Subsea Integration Alliance is a worldwide non-incorporated partnership between OneSubsea, Schlumberger, and Subsea 7 developed to jointly design, develop, and deliver integrated subsea development solutions through the combination of subsurface expertise, subsea production systems (SPS), subsea processing systems, subsea umbilicals, risers and flowlines systems (SURF), and life of field services. Its goal is delivering complementary technology and expertise that help customers extend field life and lower production costs, ensuring greater certainty of recovery and return on the investment.
Murphy Oil Corporation (NYSE: MUR) announces that a joint venture ("JV") led by its Mexican subsidiary, Murphy Sur, S. de R.L. de C.V., was the high bidder and is expected to be awarded Block 5 during Mexico's fourth phase, round one deepwater auction. Under the terms of the JV, Murphy will be the operator with a 30 percent working interest ("WI"), together with PC CARIGALI MEXICO OPERATIONS, S.A. DE C.V., a wholly-owned subsidiary of PETRONAS (23.34 percent WI), Ophir Energy (23.33 percent WI) and Sierra Offshore Exploration (23.33 percent WI).
Block 5 is located in the deepwater Salinas basin covering approximately 2,600 square kilometers (1,000 square miles), and water depths in this block range from 700 to 1,100 meters (2,300 to 3,600 feet). The initial exploration period for the license is four years and includes a work program commitment of one well.
Up to five wells will be drilled before the Mariner A platform hook up and commissioning activity starts next summer. First oil is expected to be produced from Mariner in 2018.
Hedda Felin, managing director, Statoil Production UK said, “This is an exciting period for us as a UKCS operator as we transition from the planning phase to active offshore operations.”
“Predrilling enables production to reach plateau levels more quickly after the start of operations on Mariner A. It will also be an important learning period for us in terms of understanding the reservoir and identifying potential efficiencies for future wells, with safety and the protection of the environment being our fundamental priorities.”
The Noble Lloyd Noble, the largest jack-up rig in the world. Photo credit: Statoil
The Noble Lloyd Noble, the largest jack-up rig in the world, is currently positioned over the Mariner jacket which was installed in 2015. The first production wells will be drilled through a well deck on the jacket. Up to five wells will be drilled before the platform topside modules arrive mid-2017. In total up to 100 reservoir targets could be drilled over the lifetime of the Mariner field, based on the current development strategy.
Statoil has worked closely with major contractors Noble Drilling and Schlumberger to ensure safe and cost-effective operations. The rig contract was awarded to Noble Drilling in 2013, followed by the contract award for integrated drilling and completion services to Schlumberger in 2014. The pre-drilling campaign will support around 500 jobs in the UKCS.
The Mariner topside modules are currently under construction at Daewoo Shipbuilding & Marine Engineering Co., Ltd. (DSME) in South Korea and sailaway is expected in the first half of 2017.
Mariner is one of the largest projects currently under development in the UKCS. Contracts worth over £1billion have been awarded to date to the UK supply chain by the project.
Statoil (U.K.) Limited is the operator of Mariner with 65.11% equity. Co-venturers are J.X. Nippon Exploration & Production (UK) Limited (20 %), Siccar Point Energy (8.89%) and Dyas Mariner Limited (6%).
The Mariner field is located on the East Shetland Platform of the UK North Sea, approximately 95 miles or 150 kilometers east of the Shetland Isles. The heavy oil field has reserves estimated at more than 250 million barrels of oil with an average plateau production of around 55,000 barrels per day.
The field will provide a long-term cash-flow over a 30-year field life. Production is expected to commence in 2018.
The concept chosen includes a production, drilling and quarters (PDQ) platform based on a steel jacket, with a floating storage unit (FSU).
The steel jacket for the Mariner A platform was completed on time and within budget at the Dragados Offshore S.A. yard in Spain, and safely installed in the field in September 2015.
The Floating Storage Unit - Mariner B – is fully installed in the Mariner field with around 20 people on board.
Noble Corporation’s «Noble Lloyd Noble» jack-up rig – which will assist the drilling of Mariner wells for the initial years – was constructed in Singapore and arrived in the Mariner field earlier in November.
The rig, the largest jack up in the world, stands 215m tall.
The pipelines are installed in the Mariner field, and other subsea, umbilical, risers and flowline (SURF) operations have been completed.
Statoil has been awarded blocks 1 and 3 in the Saline Basin in the Deepwater exploration tender in the Mexican Round 1.
The blocks cover an area of about 5,650 km2 (approx. 2,200 square miles) in the largely unexplored deepwater areas of the Saline Basin. Statoil will be the operator of blocks 1 and 3, at 33.4% equity, with partners BP and Total participating equally with the remaining equity.
Map image: Courtesy: Statoil
The licenses were awarded in a competitive bid round. A total of 10 deepwater blocks were on offer, with four in the Perdido Area and six in the Saline Basin.
The blocks awarded are in water depths ranging from about 900 – 3,200 meters. The bid round is Mexico’s first ever tender for deepwater exploration acreage.
“Mexico’s opening presents the industry with great opportunities, so we are pleased to secure an early position. The award grants Statoil access to significant frontier acreage in an underexplored part of offshore Mexico. The blocks are virtually untested, with considerable subsurface uncertainty, but with play-opening potential,” says Tore Løseth, Statoil’s vice president for exploration in the US and Mexico.
The winning bids for both blocks consisted of an additional royalty of 10% (on potential future revenues) and an additional work program equivalent to 1 biddable well per block. Each block also has a minimum work program as defined by the authorities, including a variety of geological activities but no required wells.
“The licenses awarded reinforces Statoil’s exploration strategy of early access at scale. This further strengthens and develops the optionality in Statoil’s long-term international portfolio,” says Løseth.
“With the Deepwater tender bringing Mexico’s historic Round 1 to a conclusion, we are starting to see the fruits of Mexico’s comprehensive energy reform. Statoil has a long-term perspective in Mexico, and we look forward to contributing to developing the energy sector by assessing the blocks awarded,” says Løseth.
Statoil has had a representative office in Mexico City since 2001.
Total has been awarded exploration licenses on 3 Blocks in offshore Mexico, following the country’s first competitive deep water bid round.
Total will be operator of Block 2 in the Perdido basin with a 50% interest, while ExxonMobil has the remaining 50%. The block covers a surface area of 2,977 square kilometers at water depths ranging from 2,300 to 3,600 meters.
In the Salina basin, Total has won a participating interest of 33.3%, alongside Statoil (33.4%) and BP (33.3%), in Blocks 1 (2,381 km²) and 3 (3,287 km²).
“With our successful bids in these promising deep water prospects, Total has seized the opportunity to benefit from Mexico’s energy reforms. Our winning bids add high-grade exploration potential to our portfolio,” said Arnaud Breuillac, President Exploration & Production at Total. “We now look forward to launching exploration works and expanding our cooperation with Mexico together with our partners.”
Subsea 7 S.A. (Oslo Børs: SUBC, ADR: SUBCY) announces the award of a sizeable contract by Woodside Energy Ltd for the Greater Western Flank Phase 2 Project, offshore Australia.
The Greater Western Flank is located on the North West Shelf of Australia, 60 km southwest of the Goodwyn Alpha (GWA) platform. The contract scope comprises the subsea tie-back of adjacent fields to the GWA platform, including the installation of manifolds, umbilicals and spool pieces, together with the pre-commissioning of the system.
Project management and engineering will commence immediately from Subsea 7's office in Perth, Australia, with offshore operations scheduled to commence in 2018.
Andy Woolgar, Managing Director, Australia and New Zealand, said: "We are delighted to have been awarded this project from Woodside Energy Ltd. This is the fourth award from Woodside in recent times, and we are pleased to be able to continue this strong working relationship."
(1) Subsea 7 defines a sizeable contract as being between USD 50 million and USD 150 million.
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