GENERAL INTERESTQuick Takes
Operator ‘reassured’ by Lopez Obrador talk
President-elect Andres Manuel Lopez Obrador of Mexico has assured oil and gas executives he will honor existing contracts, according to the chief executive of a Canadian company specializing in onshore Mexican operations.
At a recent meeting of AMEXHI, an association of oil and gas producers, Lopez Obrador stressed the importance of private-company participation in oil and gas development and future production, reported Craig Steinke, chief executive officer of Renaissance Oil Corp., Vancouver, BC.
Renaissance has interests in the Chicontepec trend of east-central Mexico and in the Chiapas-Tabasco onshore producing region (OGJ Online, Aug. 30, 2016).
Before his election, Lopez Obrador had been critical of energy-law reform, made by outgoing President Enrique Pena Nieto, that opened Mexican exploration and development to private and foreign investment. Concern has arisen about how the government will treat contracts after Lopez Obrador takes office Dec. 1 and whether it will remain committed to reform.
Renaissance, which belongs to the association at which Lopez Obrador spoke, said in a press release that the new president’s designation of Rocio Nahle as energy ministers “confirmed the incoming administration’s support for the contracts as well as a commitment to resolving regulatory delays.”
Steinke said, “Renaissance is reassured by these developments and encouraged that the Mexican government is supportive of the important role international oil companies, like Renaissance, play in the development of the Mexican petroleum industry.”
IFR receives option to buy Tonalli shares
Petro Frontera, a wholly owned subsidiary of International Frontier Resources Corp. (IFR), Calgary, has received an option to buy all shares of the Mexican Tonalli Energia joint venture held by partner Grupo IDESA.
Through Petro Frontera, IFR holds 50% of outstanding Tonalli shares. IDESA holds the rest.
Tonalli has a license for oil and gas development on Tecolutla Block in Veracruz, Mexico (OGJ Online, Aug. 8, 2018).
On exercise of the option, which expires on Sept. 25, 2020, IDESA would receive 70 million shares of IFR, less the number of shares to which it has agreed to subscribe for at least $1 million (Can.) in a private placement to be completed before Mar. 25, 2019.
Equinor buys stake in Rosebank project off the UK
Equinor has signed an agreement to acquire Chevron Corp.’s 40% operated interest in the Rosebank project, one of the largest undeveloped fields on the UK Continental Shelf. Once concluded, Equinor says, the transaction will strengthen its UK portfolio, which includes the Mariner development, exploration opportunities, and three producing offshore wind farms.
“Today’s agreement allows us to buy back into an asset in which we previously had a participating interest, demonstrating our strategy of creating value through oil-price cycles,” said Al Cook, Equinor executive vice-president for global strategy and business development and UK country manager.
Rosebank field, which lies 130 km northwest of the Shetland Islands in 1,110 m of water, was discovered in 2004. Other field partners are Suncor Energy 40% and Siccar Point Energy 20%.
“As we have done with other projects in our portfolio, such as Johan Castberg and Bay du Nord, we intend to leverage our experience and competence to create further value in Rosebank, in alignment with the UK government’s priority of maximizing the economic recovery of the UKCS,” says Hedda Felin, Equinor’s senior vice-president for UK and Ireland offshore.
PGNiG to acquire Tommeliten interests from Equinor
PGNiG will acquire non-operated interests in the Tommeliten discovery on the Norwegian Continental Shelf in the greater Ekofisk area from Equinor for $220 million. Equinor will divest its 42.38% interest in the Tommeliten Unit (PL 044 TA) and 30% interest in PL 044. Both are operated by ConocoPhillips.
Discovered in 1976, net recoverable resources in the Tommeliten Alpha natural gas and condensate discovery total 52 million boe. According to current plans, production is expected to begin in 2024, and the development concept assumes subsea tie-back to the existing infrastructure on Ekofisk, allowing for a cost-effective development, further decrease of future production cost, and an acceleration of the field’s start-up, PGNiG said.
According to PGNiG estimates, the acquisition will increase the company’s Norwegian gas production by 500 million cu m/year in the first 6 years of production and allow PGNiG to extract 500,000 tonnes of oil and NGL in the peak production year.
“It is from here that we plan to send gas to Poland via Denmark through planned Baltic Pipe pipeline,” said Piotr Wozniak, PGNiG management board president.
Exploration & DevelopmentQuick Takes
BP granted approval for Alligin development
BP PLC expects production to begin in 2020 from Alligin oil field in the North Sea, for which it has received development approval from the UK Oil & Gas Authority.
Alligin is a 20 million-bbl recoverable oil field in the Greater Schiehallion area about 140 km west of Shetland in 475 m of water. It is expected to produce 12,000 boe/d (gross) at peak from two wells tied back to the existing Schiehallion and Loyal subsea infrastructure using processing and export facilities of the Glen Lyon floating production, storage, and offloading vessel. The development will include new subsea systems comprised of gas lift and water injection pipeline systems and a controls umbilical. The wells will be drilled by the Deepsea Aberdeen rig.
Alligin is operated by BP with 50%. Shell, with the other 50%, is BP’s partner.
BP North Sea Regional Pres. Ariel Flores said, “Alligin is part of our advantaged oil story, rescuing stranded reserves and tying them back into existing infrastructure. Developments like this have shorter project cycles, allowing us to bring on new production quicker. These subsea tiebacks complement our major start-ups and underpin BP’s commitment to the North Sea.”
Greater Buchan licensing round planned
The UK Oil & Gas Authority (OGA) plans a supplementary licensing round in the first quarter of 2019 for the Greater Buchan Area in the Outer Moray Firth offshore Scotland.
The area includes “considerable open, currently unlicensed acreage, including a number of undeveloped discoveries,” the authority said (OGJ Online, Oct. 9, 2017).
OGA has begun a new area plan for the area, where it estimates the oil and gas resource at 150-300 million boe.
New data will support the round. OGA will hold an information session on Nov. 15 in Aberdeen.
SOCAR-BGP venture to explore Caspian
State Oil Co. of the Azerbaijan Republic (SOCAR) and China National Petroleum Corp. subsidiary BGP Inc. have signed an agreement forming a joint venture to conduct seismic exploration in Azerbaijan and the Caspian Sea.
The companies in June had signed a memorandum of understanding to cooperate in geological and geophysical services.
They didn’t indicate when surveys might begin.
Novatek reports gas, condensate discovery
Novatek said drilling and testing by subsidiary Arctic LNG 3 have confirmed a natural gas and condensate discovery on the North-Obskiy license in shallow waters of Ob Bay in Russia’s Yamal-Nenets Autonomous Region.
Novatek estimated gas reserves of North-Obskoye field at more than 320 billion cu m under the Russian classification system.
Savannah reports fifth Niger oil strike
Savannah Petroleum PLC, London, will assess the R3 section of its R3/R4 production-sharing contract block in southeastern Niger with prestack depth migration (PSDM) of 3D seismic data after logging its fifth oil discovery in the area.
Wireline logs, fluid samples, and pressure data indicate the Zomo-1 wildcat encountered 5.4 m of net oil pay in the E1 unit of the Eocene Sokor Alternances primary target.
Drilled to 2,499 m MD, the Agadem Rift basin well encountered target formations near expected depths.
Savannah Chairman Steve Jenkins said the five discoveries “enable us to proceed towards our planned 2019 early-production system,” which the company earlier said would follow production tests of at least two of the discoveries.
Savannah said PSDM of seismic data acquired over the eastern part of the R3 area will provide “a significantly enhanced definition of the oil pay zones at the crests of each of the discoveries and significantly assist in full ‘field scale’ evaluations and associated development planning.”
The company also expects the processing to enhance 3D imaging of undrilled deeper Cretaceous Yogou and Donga targets identified in existing data. It noted “potentially significant structures” underlying its Amdigh, Bushiya, and Eridal finds.
Savannah has received an additional 400 line-km of 2D seismic data in the central R3 area, which it will incorporate into its subsurface model.
OIL reports two gas discoveries in Assam
Oil India Ltd. reported two gas discoveries in Assam, India.
The West Lohali-1 well encountered a sand reservoir in the Oligocene Barail formation. The well tested 115,000 standard cu m/day of gas from 13 m of pay at 2,357 m.
The Dhakuwal-1 well cut two zones in the Eocene LK+TH formation. On test, one 15-m zone at 3,875 m produced 100,000 standard cu m/day of gas with 22 cu m/day of condensate.
Drilling & ProductionQuick Takes
US regulators approve more development in NPR-A
US government regulators approved ConocoPhillips Alaska Inc.’s plan for development of its Greater Mooses Tooth 2 (GMT2) project in the National Petroleum Reserve-Alaska. The approval came less than 2 weeks after oil production started from Greater Mooses Tooth 1 (GMT1).
GMT1, a satellite development of Alpine field, is connected by road to drill site CD5. GMT1 has an 11.8-acre drilling pad, a 7.6-mile road, and a pipeline connected to the Colville River Unit infrastructure.
The GMT1 pad will have nine wells initially with capacity for as many as 33 wells. Peak gross production is estimated at 25,000-30,000 b/d. The project is expected to cost about $725 million.
The Bureau of Land Management and Army Corps of Engineers issued a record of decision for a second drillsite in the GMT Unit. GMT2 is 8 miles southwest of GMT1.
Pending a final investment decision, ConocoPhillips expects construction on GMT2 could begin in early 2019. GMT2 is estimated to cost more than $1 billion, with peak production estimated at 35,000-40,000 b/d.
ConocoPhillips Alaska operates the GMT and Colville River units, holding 100% interest.
ExxonMobil lets subsea contract for Liza Phase 2
ExxonMobil Corp. affiliate Esso Exploration & Production Guyana Ltd. has let a contract to TechnipFMC for the engineering of the subsea system for the proposed Liza Phase 2 project on the Stabroek block offshore Guyana.
Following engineering and subject to requisite government approvals, project sanction, and an authorization to proceed with the next phase, TechnipFMC will manufacture and deliver the subsea equipment, which would include 30 enhanced vertical deepwater trees and associated tooling, as well as eight manifolds and associated controls and tie-in equipment.
In support of this project, TechnipFMC will continue hiring and training Guyanese engineers.
The Liza Phase 2 development is 193 km offshore Guyana in 1,500-1,900 m of water.
The potential production concept for Liza Phase 2 involves a second floating production, storage, and offloading vessel and related subsea equipment, umbilical, risers, and flowlines. The proposed development concept is like that of Liza Phase 1. About 35-40 wells may be drilled at two subsea drill centers, consisting of a combination of producers and injectors to support production of oil, injection of water, and reinjection of associated gas. The FPSO will have an estimated production capacity of 190,000-220,000 b/d of oil.
BP starts production from Thunder Horse NW expansion
BP PLC has started production from the Thunder Horse Northwest expansion project in the deepwater Gulf of Mexico, boosting production at the Thunder Horse facility by an estimated 30,000 boe/d at its peak and taking gross output from the oil field to more than 200,000 boe/d.
Originally planned for start-up in early 2019, the expansion came online 4 months ahead of schedule and 15% under budget
The project adds a subsea manifold and two wells tied into existing flowlines 2 miles north of the Thunder Horse platform and is the fourth upstream major project to begin production for BP globally so far this year.
In 2017, an expansion of Thunder Horse’s south field—a 4-well tie-back to the floating hub—boosted gross production at the field by more than 50,000 boe/d. The year before, BP started up a major water injection project at Thunder Horse to further enhance oil production from the field.
The Thunder Horse platform is in more than 6,000 ft of water and began production in June 2008. It has the capacity to handle 250,000 bbl gross of oil and 200 MMcfd gross of natural gas. The facility continued to operate during construction and installation of the subsea production and pipeline system.
Thunder Horse is operated by BP with 75% working interest. Partner ExxonMobil Corp. holds the remaining interest.
Equinor starts production from Oseberg Vestflanken 2
Equinor and partners started production from Oseberg Vestflanken 2 field in the North Sea using the first unmanned platform on the Norwegian Continental Shelf.
Remotely operated from the field’s center, the new Oseberg H platform is fully automatic and serves as a pilot, said Anders Opedal, Equinor’s executive vice-president for technology, projects, and drilling. “We are further developing the concept and believe that the next version will be even more competitive.”
The 11 wells on Oseberg Vestflanken 2 will be drilled by the Oseberg license-owned Askepott jack up rig. Nine wells will be drilled through the platform and two through an existing subsea template. Pipelines and subsea equipment have been installed. Recoverable resources are 110 million bbl.
At 6.5 billion kroner, the project was delivered more than 20% below the cost estimate of the plan for development and operation. The breakeven price was reduced from $34/bbl to below $20/bbl.
Production starts at Lula Extreme South in Santos basin
New, deepwater production has started from the Lula Extreme South in Brazil’s Santos basin from Petroleo Brasileiro SA’s (Petrobras) P-69 floating production, storage, and offloading vessel, said Shell Brasil Petroleo Ltda.
The P-69 FPSO is a standardized vessel able to process up to 150,000 b/d of oil and 6 million cu m/day of natural gas. It will ramp up production through eight producing and seven injection wells.
Petrobras is the Lula consortium operator with 65% interest. Shell has 25% interest. Petrogal Brasil holds 10% interest.
PROCESSINGQuick Takes
MMEX Resources lets contract for Texas refinery
MMEX Resources Corp.—a development-stage company focusing on acquisition, development, and financing of oil, gas, refining, and infrastructure projects in Texas and South America—has let a contract to Blanchard Industrial LLC (BIL) to provide engineering, procurement, and construction on the first 10,000-b/d phase of its proposed Pecos County, Tex., refinery near the Sulfur Junction spur of the Texas Pacifico railroad, about 20 miles northeast of Fort Stockton (OGJ, Dec. 4, 2017, p. 22).
As part of the contract, BIL will serve as overall EPC contractor to complete detailed engineering on and build the Pecos County crude distillation unit, which will produce diesel, naphtha, and residual fuel oil, MMEX said.
Phase 2 of the project will include a full-scale refinery with capacity of up to 100,000 b/d. The refinery, once completed, would be strategically situated along the Texas Pacifico-South Orient Railroad—which interconnects to the Dallas-Fort Worth area, the Texas Gulf Coast, and Mexico at Presidio—enabling MMEX to leverage existing rail, roadway, and pipeline infrastructure for both crude supply and sale of refined products internationally.
Commercial operations for Phase 1 of the project are projected to begin in mid to late 2019, according to MMEX’s web site.
Lukoil lets EPC contract for Kstovo coker
Lukoil NizhegorodNefteorgSyntez has let an engineering, procurement, and construction contract to McDermott International Inc. for a delayed coking unit at the 17 million-tonne/year refinery at Kstovo in Central Russia’s Nizhny Novgorod region. The 2.1 million-tpy coker will be part of a deep-conversion complex under construction at the refinery. Scheduled for start-up in 2021, the complex also will include a diesel hydrotreater, gas fractionation unit, sulfur and hydrogen production units, and associated systems.
The coker will use technology of Chevron Lummus Global, a joint venture of Chevron and McDermott, which also has a contract for detailed engineering, procurement, and long lead supply for the project. McDermott called the EPC contract “significant,” indicating a value of $250-500 million.
TRANSPORTATIONQuick Takes
Inpex group ships first LNG from Ichthys project
The Inpex Corp.-led joint venture’s first cargo of LNG from the Ichthys project has been shipped from the onshore gas liquefaction plant in Darwin, Northern Territory.
Inpex said the Pacific Breeze LNG carrier sailed from the terminal late on Oct. 22 bound for the Inpex-operated Naoetsu LNG receiving terminal in the Niigata Prefecture in Japan.
Inpex Australia Pres. Director Seiya Ito said the first cargo from Ichthys was an historic moment for the company and for Australia.
The $34-billion project will have a 40-year operating life and deliver benefits to the Australian economy and community for decades to come, Ito said.
The project will gradually increase its production to about 8.9 million tonnes/year of LNG when it reaches the production plateau—a figure equivalent to more than 10% of Japan’s annual LNG import volume.
About 70% of the LNG produced by Ichthys LNG is scheduled to be supplied to Japan.
The first LNG cargo follows shipment of the first condensate direct from the field production facilities offshore Western Australia earlier this month. Shipments of LPG are scheduled to begin before yearend.
Along with production of 8.9 million tpy of LNG, the project also will produce as much as 1.65 million tpy of LPG and as much as 100,000 b/d of condensate.
Victoria slows AGL Energy’s LNG plans
Sydney-based AGL Energy’s plans to establish an LNG import terminal at Crib Point in Victoria by 2021 will be delayed following the Victorian government’s call for the company to submit a full environmental assessment of the project.
The review process typically takes up to 12 months. That means AGL’s planned schedule for a final investment decision for the $250-million (Aus.) development by midyear 2019 is unlikely to be met.
AGL, nevertheless, said it was committed to the project and to working with the surrounding community as well as following all state and regulatory assessment requirements.
The company noted that Crib Point will be a safe and environmentally responsible project that will provide a secure gas supply for Victorians. It is reported that the government’s move is in response to protests from the community surrounding the Western Port location. AGL’s plan includes building a jetty to accommodate a regasification vessel plus a gas pipeline to hook into the Victorian gas grid.
The Victorian Planning Minister Richard Wynne said it was critical to assess the impacts of the project to protect the community and the environment.
Exact details of the review have not yet been released, but they are expected to include the impact of the floating storage and regasification unit on the internationally recognized wetlands region around the proposed jetty and pipeline route.
Crib Point is the former site of BP’s Victorian refinery.
The Victorian Labor government is heading into a state election on Nov. 24.
Imperial restarts Norman Wells production, Line 21
Imperial Oil Ltd. has restarted production at its Norman Wells operations in the Northwest Territories following the return to service of Enbridge Inc.’s Line 21 pipeline.
Imperial had previously resumed limited shipments of oil from storage in September. The company expects production to ramp up in the months ahead to about 10,000 b/d, consistent with rates prior to the shutdown.
Norman Wells also will resume supplying Northwest Territories Power Corp. (NTPC) with electricity. The operation generates electricity for its own use, and sells surplus to NTPC, which supplies the town of Norman Wells.
In December 2016, Enbridge proactively suspended shipments on Line 21 due to slope stability concerns on one section at the Mackenzie River crossing about 10 km east of Fort Simpson. Following a lengthy regulatory process (Canada’s National Energy Board approving the project in January) replacement work started on the 2-km section of the 870-km pipeline in May and was completed in September.
The 12-in. OD pipeline, with a design capacity of 50,000 b/d, carries Norman Wells production to Zama, Alta., where it enters a third-party system for shipment to Edmonton.
