Aberdeen-based AISUS Offshore has made significant progress in growing its global footprint following the award of 15 contracts and work scopes over the past three months.
The company has reported that 20% of its revenues are now generated by business secured overseas.
Most recently, AISUS completed four J-Tube inspections on a platform located in the Mediterranean Sea for a world leading oil services firm. More than 750m of inspection data was gathered using AISUS’ bespoke crawler-driven inspection system.
Stuart Lawson, Managing Director, AISUS Offshore
AISUS has also completed internal caisson inspection projects in Norway and Denmark, utilizing its custom engineered Aquarius system to perform corrosion mapping over the entire internal surface of the caisson. Prior to the launch of this technology, there was no way to perform full length corrosion mapping on subsea and topside structures in the same deployment.
Stuart Lawson, managing director of AISUS Offshore, commented: "Collectively, these contracts represent an exciting new phase for AISUS as we look to cement our position as one of the industry’s leading inspection specialists, both in the UK sector and overseas.
“Over the past four years, we have worked hard to create a step-change in both technology and application mind-set to deliver precise inspection solutions, whilst reducing costs, without sacrificing the quality of our products or personnel.”
“The requirements for installations to be cost-effective and environmentally secure are ever increasing and monitoring their condition is essential to ensure integrity. Deterioration can be significant, with serious consequences for installation integrity if not managed properly. By challenging conventional and established techniques, and working in collaboration with carefully selected partners, we believe enhancements can always be found.”
“We understand the need to develop technology that maximizes data accuracy and minimizes the duration of offshore inspections to satisfy the rigorous demands of the oil and gas sector, drive down costs and, ultimately, increase production.”
Specializing in the inspection of caissons and risers at all stages of the asset lifecycle, from commissioning, through operations, to decommissioning, AISUS has developed market leading technology, including a diverse range of visual and ultrasonic scanning systems.
Looking ahead, the north-east firm aims to establish strategic local partnerships and operating bases in key international locations over the next three years so it can continue to expand, increase its service offerings and develop the technologies which will help sustain long-term growth.
“Reliable and meaningful inspection data must be acquired in order to make comprehensive integrity assessments of offshore pipework and structures. Asset integrity continues to be a major priority for North Sea operators, and through our wide range of bespoke inspection services we will continue to support the industry to ensure safe and cost-effective operations across the UKCS and beyond,” added Mr. Lawson.
Established in 2013, AISUS Offshore is an innovative, technology driven company delivering remotely deployed visual and ultrasonic inspection solutions to the global oil and gas industry.
Noble Corporation plc (NYSE: NE) has announced that the Company and certain subsidiaries of Royal Dutch Shell plc (NYSE: RDS.A) have agreed to amend the existing long-term contracts on three ultra-deepwater drillships. In the current, challenging environment for offshore exploration and production projects, the agreements offer benefits for both parties.
The contract amendments pertain to the Noble Bully II, Noble Globetrotter I and Noble Globetrotter II, which are operating under 10-year term contracts that commenced in April 2012, July 2012 and September 2013, respectively.
Noble Bully II. Photo credit: Noble Corporation
Under the agreements, dayrates for each rig are now determined by taking the higher of 1) a newly established minimum dayrate, (or floor), or 2) the dayrate adjustment mechanism, as originally included in the contract. The contract amendments for the Noble Globetrotter I and Noble Globetrotter II provide for a dayrate floor of $275,000 per day, representing a minimum market rate if the dayrate adjustment mechanisms for these two rig contracts stay below that level. The Noble Bully II contract contains a floor dayrate, which is $200,000 per day plus daily operating expenses.
Additionally, Shell was granted and has exercised the right to idle the Noble Globetrotter II for a period of up to 730 days, which is expected to occur in January 2017. During the idle period, a negotiated rate of $185,000 per day will be paid. Shell was also granted and is expected to exercise the right to idle the Noble Bully II for a period of up to 365 days, commencing no later than May 2017. The Noble Bully II is part of the Bully joint-venture (Noble 50%, Shell 50%). During this idle period, a negotiated rate of $200,000 per day will be paid. Noble has discretion over each rig's operating costs throughout the idle period, with the flexibility to reduce costs over the anticipated period. If warm stacked, Noble expects daily cost savings on each rig of at least $100,000 per day, with additional cost savings should Noble elect to cold stack the units. In addition, Noble can enter into contracts with third parties for the Noble Globetrotter II and the Noble Bully II during the idle periods. Noble would be responsible for operating expenses and would also retain any incremental revenue received from such third party contracts. Other than the new dayrate floor, no changes were made to the Noble Globetrotter I dayrates.
The dayrate adjustment mechanism, which begins on the five-year anniversary of each of the three contracts, employs an average of market rates experienced over a defined period for a basket of rigs that match a set of distinct technical attributes, with adjustments every six months thereafter until the completion of the 10-year primary terms.
David W. Williams, Chairman, President and Chief Executive Officer of Noble Corporation plc, stated, "This mutually beneficial agreement provides Noble with clarity on dayrates and subsequent operating cash flows through the duration of the contracts on each of the three rigs. We also retain the future upside if the recent oil price recovery drives new market opportunities. These amendments will provide Noble with enhanced financial flexibility at a time when the offshore industry is experiencing a cyclical bottom and the timing of the inevitable recovery remains unknown."
The primary term for each of the drillships Noble Bully II, Noble Globetrotter I, and Noble Globetrotter II are unchanged, with contracts expected to conclude in April 2022, July 2022 and September 2023, respectively.
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.
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%).
Subsea 7 S.A. (Oslo Børs: SUBC, ADR: SUBCY) announces the award of a sizeable(1) contract by Centrica for the Oda field in the Norwegian North Sea.
The Oda oil field (previously called Butch) was discovered in 2011 in the southern part of the Norwegian North Sea, approximately 14 kilometers east of the Ula field. The contract scope comprises Subsea 7's expertise and capabilities in engineering, procurement, construction, installation and commissioning (EPCIC) of subsea umbilicals, risers and flowlines (SURF) including the production pipeline, water injection line, umbilical and related subsea services.
Project management and engineering will commence immediately from Subsea 7's office in Stavanger, Norway, with offshore operations scheduled to commence in 2018.
Phil Simons, Vice President North Sea & Canada, said: "The strategic partnership with Centrica allows the parties to work closely together to optimize the project delivery. This contract award shows that this way of working with our clients provides cost effective and optimized technical solutions, and earlier delivery of projects. We look forward to continuing to work closely with Centrica to successfully deliver the Oda project, with safety and quality at the forefront throughout the execution."
(1) Subsea 7 defines a sizeable contract as being between USD 50 million and USD 150 million.
Oil production from the Organization of the Petroleum Exporting Countries (OPEC) for November rose for the sixth straight month to a record 33.86 million barrels per day (b/d), according to a survey of OPEC and oil industry officials by S&P Global Platts, the leading independent provider of information and benchmark prices for the commodities and energy markets.
The November production figure was a 320,000 b/d rise from October output and illustrates the challenge OPEC faces implementing a production cut it finalized in Vienna last week with the aim of accelerating the global oil market's rebalancing.
Many members appear to be pumping at or close to their full capacity to maximize revenues before the OPEC deal goes into force January 1.
Under that plan, the organization will, for six months, cut 1.2 million b/d from its October output level, as calculated by an average of OPEC's six secondary sources, including Platts, and freeze production at around 32.5 million b/d.
Saudi Arabia, which has committed to holding its output at 10.046 million b/d, saw its November production drop slightly to 10.52 million b/d, indicating it has a way to go before complying with its target.
Exports of Saudi crude have been high in recent months and output has defied the usual seasonal decline, even with the peak summer air conditioning season long over, though experts expect the country to return to more typical winter consumption patterns to comply with the production cut.
Iraq, OPEC's second largest producer, saw November output hold steady at 4.56 million b/d. The country had disputed secondary source estimates of its production as too low and sought an exemption from the OPEC cuts due to its war against the Islamic State.
But Iraq ultimately agreed to the OPEC plan, which calls for the country to bring production down to 4.351 million b/d, as calculated by secondary sources.
Iran, meanwhile, raised its November production slightly from October to 3.69 million b/d. Iran, which also sought an exemption from the cuts as it aimed to regain its pre-sanctions market share, is allowed to produce up to 3.797 million b/d under the OPEC plan.
Angola showed the biggest rise in production for November, but that was expected as its key Dalia field, which produces around 200,000-250,000 b/d, was scheduled to come back online after going down for maintenance for all of October.
Angola's November production was 1.7 million b/d, up 230,000 b/d from October, with small declines in export volumes offsetting the return of Dalia. Its output target of 1.673 million b/d under the OPEC plan is based on its September level, before Dalia went into maintenance.
Nigeria, exempt from the OPEC cuts as it battles militancy in the Niger Delta, saw its production remain at 1.68 million b/d in November, unchanged from October. The loss of production of key export grade Forcados, which saw a major pipeline bombed in early November, was offset by increased exports of other grades.
Traders say they expect Forcados production to remain offline for a while, with no signs of a January loading program, and the oil-rich Niger Delta remains unstable and sensitive, with chances of more militant attacks on oil infrastructure high.
Libya, also exempt from the cuts, averaged 580,000 b/d in November, up 50,000 b/d from October, as it continues to find its footing after years of civil war.
The country had been producing 600,000 b/d at the beginning of the month, according to state-owned National Oil Corporation, but a power outage November 23 caused output to fall to 523,000 b/d.
Venezuela was the only OPEC member other than Saudi Arabia to see a fall in production, as November output slid to 2.07 million b/d amid the country's economic crisis.
The Platts estimates were obtained by surveying OPEC and oil industry officials, traders and analysts, as well as reviewing proprietary shipping data.
For output numbers by country, click on this S&P Global Platts OPEC Production Table. You may be prompted for a cost-free, one-time-only log-in registration.
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.”
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.
Shell has started oil production from the Malikai Tension-Leg Platform (TLP), located 100-kilometers off the coast of the Malaysian state of Sabah.
Located in waters up to 500-metres deep, Malikai is Shell’s second deep-water project in Malaysia, following the successful start-up of the Gumusut-Kakap platform in 2014. Malikai is expected to have a peak production of 60,000 barrels per day. As the company’s first TLP in the country, Malikai is an example of the strength of Shell’s global deep-water business, applying TLP expertise from decades of operations in the U.S. Gulf of Mexico.
Malikai Tension Leg Platform starts production. Photo courtesy: Shell
“Malikai marks an important milestone for Shell, its partners, Sabah and Malaysia. The project has demonstrated our capability in delivering competitive deep-water projects utilizing our global expertise.” said Andy Brown, Upstream Director, Royal Dutch Shell.
The project features a cost-effective platform design and a unique, industry-first set of risers, or pipes that connect the platform to the wells for oil production, which required fewer drilling materials and lower costs.
Designed and built in Malaysia, the Malikai TLP project has allowed Shell to share deep-water expertise with Malaysian energy companies, playing an active role in helping the government develop the nation’s deep-water resources and deep-water service industry.
The Malikai project is a joint venture between Shell (35%, operator), ConocoPhillips Sabah (35%) and PETRONAS Carigali (30%).
Globally, Shell’s deep-water business is a growth priority for the company and currently produces 600,000 boe/d. Deep-water production is expected to increase to more than 900,000 boe/d by the early 2020s from already discovered, established reservoirs. Two other Shell-operated projects are currently under construction or undergoing pre-production commissioning: Coulomb Phase 2 and Appomattox in the U.S. Gulf of Mexico. In September 2016, Shell announced the start of production at Stones in the Gulf of Mexico, the world’s deepest offshore oil and gas project beneath 2,900 meters of water.
For more information on Shell’s deep-water projects around the world visit: www.shell.com/deepwater
The Bureau of Ocean Energy Management (BOEM) completed its required evaluation to ensure the public receives fair market value for tracts leased in Western Gulf of Mexico Oil and Gas Lease Sale 248, held on August 24, 2016.
After extensive geological, geophysical, engineering, and economic analysis, BOEM has awarded all 24 leases on tracts covering 138,240 acres to high bidders who participated in the sale. The accepted high bids are valued at $18,067,020. BOEM accepted the 24 bids after determining that the value of each bid was sufficient to provide the public with fair market value for each tract. The highest bid accepted was $1,124,000, submitted by Exxon Mobil Corporation for East Breaks, Block 590. BHP Billiton Petroleum (Deepwater) submitted 12 of the 24 bids.
During the sale, three companies submitted 24 single bids totaling $18,067,020. No bids were received in water depths less than 800 meters or greater than 1,600 meters. By comparison, during last year’s Western Sale 246, 33 tracts received single bids totaling $22,675,212. Five of the bids were in water depths less than 800 meters and 21 were in water depths greater than 1,600 meters. For more information on Sale 248 click here.
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.
EnerMech has been awarded its first contract by Subsea 7 in the Australian oil and gas market.
The mechanical engineering group will perform a range of subsea flowline and umbilical pre-commissioning on the Woodside-operated North West Shelf (NWS) Project’s Persephone project and North Rankin Complex in Western Australia.
The workscope includes flooding, hydro-testing and dewatering of flow lines & well jumpers and testing all hydraulic, electrical and optical cores on the main line umbilical, EFL’s and HFL’s with work expected to start this month (December).
EnerMech is one of the foremost suppliers to large scale oil, gas and LNG projects in Australia and has seven bases in-country, including Perth, Melbourne, Darwin and Gladstone.
The company already undertakes specialist testing work on the North Rankin Complex for Wood Group PSN so can offer continuity and familiarity with Woodside and North Rankin requirements.
EnerMech’s Australia regional director, Allan Hart, said: “As a company, we have a strong relationship with Subsea 7 in the major international oil and gas producing hubs and we are delighted to consolidate this link with our first contract award in Australia.
“We place a heavy emphasis on innovation and trying to find fresh solutions to client requirements and our proposal fitted well with Woodside’s specification for the flooding, cleaning and testing of offshore pipelines.
“Our strong reputation for competent umbilical testing, investment in the latest equipment and a collaborative approach to delivery, has put us in a good positon to win other strategic contracts on major Australian oil and gas projects.”
BP has sanctioned the Mad Dog Phase 2 project in the United States, highlighting its long-term commitment to the country despite the current low oil price environment.
Mad Dog Phase 2 will include a new floating production platform with the capacity to produce up to 140,000 gross barrels of crude oil per day from up to 14 production wells. Oil production is expected to begin in late 2021.
Photo credit: BP
“This announcement shows that big deepwater projects can still be economic in a low price environment in the U.S. if they are designed in a smart and cost-effective way,” said Bob Dudley, BP Group Chief Executive. “It also demonstrates the resilience of our strategy which is focused on building on incumbent positions in the world’s most prolific hydrocarbon basins while relentlessly focusing on value over volume.”
In 2013, BP (operator, with 60.5 percent working interest) and co-owners, BHP Billiton (23.9 percent) and Union Oil Company of California, an affiliate of Chevron U.S.A. Inc. (15.6 percent), decided to re-evaluate the Mad Dog Phase 2 project after an initial design proved too complex and costly. Since then, BP has worked with co-owners and contractors to simplify and standardize the platform’s design, reducing the overall project cost by about 60 percent. Today, the leaner $9 billion project, which also includes capacity for water injection, is projected to be profitable at or below current oil prices.
“Mad Dog Phase 2 has been one of the most anticipated projects in the U.S. deepwater and underscores our continued commitment to the Gulf of Mexico,” said Richard Morrison, president of BP’s Gulf of Mexico business. “The project team showed tremendous discipline and arrived at a far better and more resilient concept that we expect to generate strong returns for years to come, even in a low oil price environment.” While BP has reached a final investment decision (FID) on Mad Dog Phase 2, BHP Billiton and Chevron, for the Union Oil Company of California interest, are expected to make a final investment decision in the future.
BP discovered the Mad Dog field in 1998 and began production there with its first platform in 2005. Continued appraisal drilling in the field during 2009 and 2011 doubled the resource estimate of the Mad Dog field to more than 4 billion barrels of oil equivalent, spurring the need for another platform at the field. The second Mad Dog platform will be moored approximately six miles to the southwest of the existing Mad Dog platform, which is located in 4,500 feet of water about 190 miles south of New Orleans. The current Mad Dog platform has the capacity to produce up to 80,000 gross barrels of oil and 60 million gross cubic feet of natural gas per day.
BP plans to add approximately 800,000 net barrels of oil equivalent per day of new production globally from projects starting up between 2016 and 2020.
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.”
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