PETROFAC will undertake late-life duty holder responsibilities for BP at the Miller platform in the Central UK North Sea for an undisclosed sum.
The services company will manage all onshore and offshore work related to the transition at Miller, preparing for the next phase of decommissioning.
Although the contract term is stated as “life of asset”, BP has stipulated a four-year limit, after which extension options will be considered as required. BP remains the licence holder at Miller.
Miller is located in Blocks 16/7b and 16/8b, 270 km northeast off Aberdeen. The field was discovered in 1982 in acreage awarded to BP under the seventh UK licensing round, with oil resources located 4,000 metres below the seabed.
Miller reached peak production of 150,000 barrels per day from a 12-slot drilling template. Had BP chosen to proceed with a US$1 billion scheme to provide carbon capture storage (CCS) at Miller in 2007, the project could have recorded a 21st Century industry first. Despite two postponements aimed at securing UK government funding, which arrived too late for a viable investment, BP halted production at Miller in July 2007. BP has already undertaken well abandonment and topside clean-up operations at Miller, and anticipates full removal of the topsides in 2017-18. Three pipelines serving Miller are to be left in situ under the UK’s disused pipeline regulations, allowing BP to propose alternative usage within a ten-year period.
Miller was served by an 18-inch (457-mm) oil export pipeline sending crude for processing at the Brae A platform, and a 30-inch (762-mm) gas export pipeline to the St Fergus processing terminal. There was also a 16-inch (406-mm) two-sided link between Miller and the Brae B platform, capable of sending gas from both projects in either direction.
Miller is one of a number of UK Continental Shelf (UKCS) projects scheduled for decommissioning in the coming years. Also on the slate are the Murchison field in Block 211/19a and Brent in Block 211/19. Decommissioning spending topped GBP1 billion (US$1.45 billion) in 2014, the highest figure on record and equivalent to 4% of total UKCS investment.
Majors adopt joint approach to equipment production
Ten global oil companies including BP, Royal Dutch Shell, Total, Eni, Engie and Statoil are to collaborate to produce standardised production equipment to help drive down costs.
The so-called Standardisation of Equipment Specifications for Procurement initiative could save the companies involved billions of dollars, according to Harry Brekelmans, projects and technology director at Shell.
Items that could be mass produced at a lower cost under its auspices include bespoke valves, paints and underwater equipment, he said last week, adding that the companies also want to set up institutions to fund future savings.
“We’re coming together with a number of other operators and suppliers to focus on standardisation and common requirements and pushing it all the way into how we can create common inventory,” Brekelmans said.
Inefficiencies stemming from energy companies’ desire to protect patents for parts as basic as bolts or ladders have pushed up industry costs for years – an issue that has become critical for many as the start of the global crude price rout approaches its second anniversary.
Achieving greater standardisation should also benefit oil companies even after oil prices have recovered.
It remains to be seen, though, how well energy companies will collaborate in practice, especially as crude prices inch upwards, cost pressures ease and business-as-usual competition resumes.
“It is still too early to say whether the push for standardisation is working,” said Jon Clark, oil and gas advisor at consultancy EY. “While this is an industry that prides itself for its technology, it has not always been able to work together to lower costs, even as companies try to adjust to the lower price environment.”
One take-away from last week’s Offshore Technology Conference 2016 in Houston was also that operators across the world view equipment standardisation as key to improving field economics.
However, “what is becoming increasingly evident is that most cost reductions and solutions proposed thus far only take a haircut to costs and are temporary in nature [ie service costs] thus not transformational,” with many offshore operators continuing to hold out on standardisation, joint ventures and other steps, Raymond James & Associates energy analyst J Marshall Adkins wrote in a summary of the event.
“That said, the willingness of most companies to take these incremental changes has increased as the downturn has persisted and this industry has historically been very good at adapting to changing conditions,” he noted.
Edited by Ryan Stevenson
NSRI tackles subsea storage
On April 21, National Subsea Research Institute (NSRI) held the first of its focused workshops addressing some of the potential solutions that had been identified through the previous hackathon events.
Subsea storage has been used in the O&G environment for many years, but has not enjoyed widespread acceptance. In fact, there are only two or three tanks in use on the UKCS.
The workshop invited speakers who had expert knowledge in the field of subsea storage tanks, who brought the audience up to speed with the state of the art and the issues arising.
In the afternoon the delegates debated the way forward for subsea storage in tables under the themes, concept selection, construction, and operations. A host of issues and solutions were identified. NSRI are at present documenting this and identifying the technology gaps which it will highlight to industry as developmental opportunities.
Schlumberger ditches Fortuna FLNG plan
Schlumberger has dropped out of a plan to participate in the construction of a floating LNG (FLNG) plant offshore Equatorial Guinea. Ophir Energy announced the service company’s withdrawal on April 29, saying that plans were moving ahead regardless and that costs were falling.
However, a final investment decision (FID) on Fortuna has now been pushed back to the fourth quarter of the year, with first gas targeted for early 2020. In January, Ophir said it would reach FID by mid-year, with first gas in 2019.
Schlumberger signed on to the Fortuna FLNG scheme in January this year, under a non-binding heads of terms. Ophir said the companies had been unable to complete the transaction on the terms agreed and, as a result, talks had ended.
Ophir said that the project remained “technically and financially attractive” and that there were a number of alternatives to Schlumberger. The company went on to say talks were continuing with other parties, on various topics including equity participation, vendor financing and pre-sales of gas.
Offtakers have been narrowed down to three options, it said. Following completion of the front-end engineering and design (FEED), bids were submitted, with costs reduced from US$600 million to US$450-500 million gross. The development and production plan was submitted to Equatorial Guinea’s Ministry of Mines, Industry and Energy (MMIE) in March.
“The reduction in the capex to first gas has lowered the project breakeven oil price to approximately US$40 per barrel,” said Ophir’s CEO, Nick Cooper. “We continue to work closely with Golar, the prospective offtakers and the other potential partners and remain confident that we will take the FID in 2016.”
Schlumberger had been due to acquire a 40% economic stake in the FLNG project, with a commitment to reimbursing 50% of Ophir’s past costs. This would have covered Ophir’s share of spending to first LNG sales, it said at the time.
The service company had also signed a memorandum of understanding (MoU) with Golar LNG, focusing on developing gas reserves and FLNG. The deal, signed at the same time as the Ophir heads of terms, was to provide access to “a wide range of uneconomic gas reserves by delivering low-cost LNG production solutions”, Golar said, describing it as ground-breaking.
The two companies working together will be able to provide an integrated package, which will reduce risk and secure financing for gas projects. Its main aim will be to accelerate the time it takes to bring gas reserves into production.
Edited by Ed Reed
Shell deals blow to Norway’s Arctic ambitions
Royal Dutch Shell has announced plans to withdraw its application for Barents Sea acreage that it applied for in Norway’s 23rd licensing round.
Oslo offered 52 Barents Sea exploration blocks in December 2015, with 34 of the licences located in the southeast Barents. The area was previously inaccessible owing to territorial disputes with Russia.
The Norwegian Petroleum Directorate (NPD) received bids from 26 applicants and is forecast to announce the results later this year to allow drilling to commence in 2017.
Shell lodged several applications for licences in the southeast Barents, stressing its experience with working in Arctic conditions after campaigns in Alaska, Russia and Greenland. But on April 4, Shell’s head of oil and gas production, Andy Brown, noted that the company had already committed to exploration cutbacks in frontier regions following its US$50 billion takeover of BG Group on February 15.
Furthermore, Shell has already suffered setbacks in its campaigns elsewhere in the Arctic, having cancelled its Alaskan efforts in September 2015 after a US$7 billion exploration campaign failed to produce any tangible results.
The Anglo-Dutch super-major has set a US$33 billion capital expenditure target for this year, US$4 billion higher than its final 2015 forecast, but US$2 billion lower than previous projections for 2016.
Research by Bernstein cited by the Wall Street Journal suggests Shell could cut expenditure further to US$28 billion with cost reductions, project delays and reduced exploration expenditure.
In this context, Shell is likely to have concluded that it should avoid straining its cash flow with extra exploration obligations in a region where profitability remains unproven at current oil prices.
Arctic exploration has struggled in recent years as companies have become increasingly wary of the high costs of production and technical challenges that affect projects in the world’s northernmost reaches.
Oslo had high hopes for Arctic development after Statoil launched its Snohvit gas field in the Barents Sea in October 2007, but the pace of exploration has slowed with the collapse in crude prices.
Statoil was one of the major applicants in Norway’s latest licence round. Its senior vice president Jez Averty dismissed speculation that resources in the Barents would prove non-commercial.
Edited by Ryan Stevenson
Woodside seeks low-cost exploration opportunities
Australia ’s Woodside Petroleum has taken a cautious stance in terms of committing to large scale LNG projects but has kept an eye on potential upstream investments in Africa. In particular, the company is taking advantage of low service prices to acquire seismic in new frontiers.
Speaking during Woodside’s AGM in April, the company’s chairman, Michael Chaney, noted the agreement with Impact Oil & Gas from February.
Woodside struck a deal to acquire a 65% stake in the production-sharing contract (PSC) and joint operating agreement (JOA) on the AGC Profond block.
The block is in the joint development area between Senegal and Guinea Bissau. The deal was an example of Woodside’s exploration strategy, Chaney said, describing it as “a very prospective area” with the move building on “our other recent acreage acquisitions in Cameroon, Gabon and Morocco”.
The block covers 6,700 square km, in water depths ranging from 1,400 metres to 3,700 metres. Completion of the deal remains subject to meeting a number of conditions.
The AGC Profond is in its first exploration stage, with a work obligation covering seismic licencing, reprocessing and studies, Woodside said.
The Australian company is also working in the Rabat Ultra Deep Offshore reconnaissance licence. During the first quarter, processing of 1,074 km of new 2-D seismic was completed, it said. This will be used to determine plans for further work.
Edited by Ed Reed
MOL launches new LNG transport project in Indonesia
JAPAN’S Mitsui OSK Lines (MOL) and its partners have inaugurated a new coastal LNG transport project in Indonesia. The Triputra, an LNG carrier with a tank capacity of about 23,000 cubic metres, transported a cargo from the Bontang LNG plant in East Kalimantan to a newly built small-scale LNG receiving terminal at the Port of Benoa on Bali Island for the first time, MOL said on May 6.
The Triputra is owned jointly by MOL, GTS Internasional, PPT Energy Trading and LNG Japan. GTS Internasional is a wholly owned subsidiary of Indonesia’s Humpuss Group, while PPT Energy Trading is a Japanese subsidiary of Indonesia’s state-owned Pertamina.
The Triputra will transport between 200,000 and 300,000 tonnes per year of LNG from the Bontang plant to the Benoa LNG receiving terminal under a seven-year contract with Pelindo Energi Logistik (PEL), a subsidiary of Indonesia’s state-owned port operator, PT Pelindo III.
The LNG will be regasified at the Benoa LNG receiving terminal, which is owned jointly by Pertamina Gas (Pertagas) and Pelindo III. Pertagas is a subsidiary of Pertamina. The Benoa LNG receiving terminal consists of a floating storage unit (FSU) and a floating regasification unit (FRU).
This is MOL’s second coastal LNG transportation project in Indonesia. In 2011, MOL and its Indonesian partner, Trada Maritime, won an LNG transport contract from Nusantara Regas for the West Java LNG receiving terminal.
Nusantara Regas is a joint venture between Pertamina and Indonesia’s state-run gas distributor, Perusahaan Gas Negara (PGN). Indonesia is largely known in the LNG world as a major exporter. However, in order to meet growing domestic demand for natural gas, it intends to construct a number of receiving and regasification terminals. The country’s Arun LNG plant, in Aceh, has been repurposed from serving as an export plant to be Indonesia’s third – and first land-based – LNG receiving and regasification terminal.
Perta Arun Gas, a subsidiary of Pertagas, is the operator of the Arun LNG terminal
Edited by Andrew Kemp
Forum Energy Technologies delivers 9 subsea PLR systems
Forum Energy Technologies Inc. has successfully delivered a number of its largest subsea Pig Launchers and Receivers (PLRs) and laydown heads to a project in North Africa.
The nine PLRs have been deployed as part of a development of nine subsea wells, which vary from four to 24 inches in size, with water depths ranging from 300 to 800 metres.
The custom-designed units will be used in the completion of flooding, cleaning, gauging, strength test, intelligent pigging and dewatering activities. John Thompson, operations director at the company’s Moffat site, said that: “The scope of work for the project, which included the full design, manufacture and testing of the PLRs, underlines the fully integrated system we can offer from concept through to delivery.”
In addition to their size and weight, Forum’s PLRs have other additional capabilities compared with conventional systems because they are also equipped with a remotely operated vehicle (ROV) readable subsea flow meter, a ROV operable choke valve for discharge throttling to control the pigging velocity. Forum also developed and manufactured a landing interface from the PLR’s to the pipeline end terminator (PLET) with a horizontal driverless connection system.
FORUM ENERGY TECHNOLOGIES
ExxonMobil, FuelCell Energy tackle carbon capture technology
ExxonMobil and FuelCell Energy are to pursue new technology in power plant CO2 capture, through a new application of carbonate fuel cells. The hope is that the technology could substantially reduce costs and lead to more economical large-scale applications.
Vijay Swarup, vice president for research and development at ExxonMobil Research & Engineering Company said that: “Our scientists saw the potential for this exciting technology for use at natural gas power plants to enhance the viability of carbon capture and sequestration while at the same time generating additional electricity. We sought the industry leaders in carbonate fuel-cell technology to test its application in pilot stages to help confirm what our researchers saw in the lab over the last two years.”
Chip Bottone, president and chief executive officer of FuelCell Energy, Inc., said his company is pleased to bring its global leadership in the development of carbonate fuel cells to this project. “The carbon capture configuration has the added benefit of eliminating approximately 70% of the smog-producing nitrogen oxide generated by the combustion process of these large-scale power plants.”
Two years of laboratory tests have demonstrated that the unique integration of two existing technologies – carbonate fuel cells and natural gas-fired power generation – captures CO2 more efficiently than existing scrubber conventional capture technology. The potential breakthrough comes from an increase in electrical output using the fuel cells, which generate power, compared to a nearly equivalent decrease in electricity using conventional technology.
The resulting net benefit has the potential to substantially reduce costs associated with carbon capture for natural gas-fired power generation, compared to the expected costs associated with conventional separation technology. A key component of the research will be to validate initial projected savings of up to one-third.
The scope of the agreement between ExxonMobil and FuelCell Energy will focus, for about one to two years, on how to further increase efficiency in separating and concentrating CO2 from the exhaust of natural gas-fueled power turbines. Depending on reaching several milestones, the second phase will more comprehensively test the technology for another one to two years in a small-scale pilot project prior to integration at a larger-scale pilot facility.
KS Drilling postpones delivery of Chinese-built jack-up
DELIVERY of a Chinese shipyard-built large jack-up drilling rig capable of accommodating 150 people has been delayed for 18 months at the request of the buyer because of the offshore industry slump.
It is the second postponement by Singapore’s KS Drilling. The rig, KS Orient Star, was originally scheduled to be handed over by Cosco Nantong in 2014 before being pushed back until April this year. Now Cosco has agreed to retain the finished rig until December 2017, shipping industry magazine Splash 24/7 has said.
“In the spirit of partnership between KS Drilling and Cosco Shipyard, and in light of the currently unfavourable oil and gas market climate... KS Drilling and Cosco Shipyard have agreed to extend the time for KS Drilling to take delivery,” the Singapore company said.
The rig is one of two originally ordered by KS Drilling. The first was taken by the buyer in 2014. Splash 24/7 said the two companies had agreed that Cosco could sell the jack-up rig if the price covered both parties’ costs.
State-owned Cosco operates yards in several ports. Reports emerged in April that subsidiary Cosco Guangdong was facing financial difficulties owing to a lack of new orders and was seeking to lay off workers.
The central government is encouraging state yards to merge and consolidate, and Cosco in April was reported to be in talks on a shipyard joint venture with Kawasaki Heavy Industry of Japan involving the amalgamation of two yards in Dalian.
Meanwhile, a subsidiary of China State Shipbuilding Corp. (CSSC) is continuing to expand its fleet of very large crude carriers (VLCCs). CSSC Shipping has emerged as the secret buyer of the US$25 million second-hand VLCC sold by Germany’s DS Tanker at the beginning of this month, Splash 24/7 has reported. The Chinese shipper now has five VLCCs and is rumoured to be the buyer of a sixth second-hand crude carrier, sold by John Fredriksen’s Ship Finance International last week also for about US$25 million.
ITF-facilitated JIP to understand subsea faults enters trial phase
A joint industry project established through The Industry Technology Facilitator (ITF) has entered a trial phase with the support of oil and gas operators.
A new technology system designed to address a common problem in the subsea industry is undergoing a shallow water trial at Portishead Quays marina. The system will help to identify the location of electrical faults on subsea installations and will enable field operators to better plan for repair or replacement of failed components which could save the industry millions of pounds in halted production.
The system, known as V-IR, has been developed by Viper Subsea with the support of Total, BP, Shell, and Chevron.
The shallow water trial will run in phases and could last up to 12 months. The initial trial will take three months, during which time the V-IR technology suite will undergo communications and performance testing in a sea water environment that includes the use of 2km of subsea cable which has been deployed onto the bed of the marina.
Although a shallow water trial, the main components are already designed for 3000m water depth. Following the shallow water trial there will be a period of further equipment qualification before the system is fully commercialised later in the year.
Bidders line up for Bul Hanine phase-2 FEED
PREQUALIFIERS for the design contract on the second phase of the multi-billion-dollar redevelopment of the offshore Bul Hanine field by stateowned Qatar Petroleum (QP) have been invited to submit bids in June. This lays to rest doubts about Doha’s commitment to proceed with the costly project in light of budgetary difficulties.
Nevertheless, the scope may be somewhat smaller than envisaged at the launch of the strategically-important project two years ago – just weeks before the oil price slide began – as the state prepares to fall into its first fiscal deficit for more than a decade this year.
Meanwhile, a reminder of the undecided fate of the Al-Shaheen field to the north – tendered among international oil majors in mid-2015 and offering a rare opportunity to obtain Gulf upstream equity – was provided by the longstanding incumbent operator Denmark’s Maersk Oil, in statements signalling less confidence than had previously been professed in the likelihood of its retaining the role.
A shortlist understood to comprise Norway’s Aker Solutions, Fluor and Wood Group Mustang, both of the US, the UK’s Amec Foster Wheeler, France’s Technip and Australia’s WorleyParsons has been invited to bid by earlyJune for the front-end engineering and design (FEED) contract on the second phase of the project – launched in May 2014 and valued initially at US$11 billion – to redevelop Bul Hanine. The 80-square-km field that is operated by QP lays off the emirate’s east coast, having been discovered in 1972 and currently produces around 40,000 barrels per day.
As originally conceived, the scheme aimed to roughly double production to around 95,000
bpd and – in keeping with Doha’s driving motivation across its various oil-producing assets – to extend the field’s life by around 25 years. The scope was to include drilling 150 wells, installing 14 new wellhead jackets, modifying existing jackets, and building a new central processing complex for the oil and a new natural gas liquids (NGL) plant at Mesaieed – connected by a 150- km subsea pipeline to the field. This will treat an estimated 900 million cubic feet (25.5 million cubic metres) per day of sour gas, returning dry gas to the field for re-injection.
Work on the smaller first-phase of development is already under way. US-based McDermott won an engineering, procurement, construction and installation contract (EPCIC) in October covering four topsides weighing a combined 3,500 tonnes due for delivery by July 2017. Meanwhile, in January, WorleyParsons was selected for the FEED contract on the so-called phase 1B covering five topsides for wellhead platforms, pipelines, umbilicals and modifications to existing facilities.
TEXAS-BASED NextDecade has filed its application with the US Federal Energy Regulatory Commission (FERC) to build and operate its proposed Rio Grande LNG project.
The US$20 billion, 27 million tonne per year LNG terminal would be located at the Port of Brownsville in Texas. The FERC application also includes a 137-mile (220-km) pipeline system from the Agua Dulce Hub that will supply gas to the facility.
NextDecade said it was now “in an excellent position to sign offtake agreements and declare final investment decision [FID] in 2017” for the project. “Despite recent low oil and gas prices, we have found robust appetite for US LNG on a long-term basis all around the world,” said NextDecade’s CEO, Kathleen Eisbrenner. “This interest reaffirms the price competitiveness of US LNG for customers looking to diversify their gas supply on a global level.”
The San Antonio Business Journal reported that NextDecade had already signed non-binding agreements to deliver 26 tonnes per year of LNG to customers globally.
In its application, NextDecade asked regulators for permission to use gas from the Eagle Ford shale in South Texas as feedstock for the export project.
According to the FERC filing, the terminal would include six liquefaction trains with a nominal capacity of 4.5 million tonnes per year each, four LNG tanks with a capacity of 180,000 cubic metres each, two marine jetties for oceangoing LNG vessels with capacities of 125,000-185,000 cubic metres, one turning basin and four LNG and two natural gas liquids (NGL) truck-loading bays.
The pipeline system would include twin, parallel 42-inch (1,067-mm) diameter pipelines, three 180,000 hp compressor stations, two 30,000 hp interconnect booster stations, six mainline valve sites and four metering sites along a 2.4-mile (3.9-km) header system, as well as ancillary facilities.
In other news, last week FERC authorised a proposed expansion of Sempra Energy’s Cameron LNG export terminal being built near Hackberry, Louisiana. Sempra proposed adding two liquefaction trains to the three already being built at Cameron LNG.