OGJ Newsletter

Exploration & DevelopmentQuick Takes

Eni reports oil discovery off Angola

Eni says an oil discovery on Block 15/06 offshore Angola opens a new play concept. The Agogo-1 NFW well penetrated a 203-m oil column with 120 m of net pay in Lower Miocene sandstones in subsalt diapirs. Oil is 31° gravity.

The well was drilled to 4,450 m TD in 1,636 m of water about 180 km off the coast. It’s 20 km west of the N’Goma floating production, storage, and offshore vessel (West Hub).

Eni estimates oil in place at 450-650 million bbl. “The discovery opens new opportunities for oil exploration below salt diapirs in the northwest part of the prolific Block 15/06,” Eni said. The company said it will study fast-track development.

Agogo is the third commercial discovery in a Block 15/06 exploration program begun last year. Others are Kalimba and Afoxe. Eni operates the block with a 36.8421% interest.

Inpex awarded onshore Block 4 in Abu Dhabi

Inpex Corp. has received exploration rights to 6,116-sq km Block 4 in Abu Dhabi from Abu Dhabi National Oil Corp.

With a 100% interest in the exploration phase, Inpex will invest as much as $176 million, including a participation fee, to explore the area between Abu Dhabi city and the boundary with Dubai and to assess two undeveloped discoveries, Ramhan and Hudairiat.

Inpex will drill wells and contribute financially and technically to an ADNOC seismic survey encompassing the area.

Block 4 is near onshore Al Dabbi’ya and Rumaitha and offshore Umm Al Dalkh oil fields. Jodco Exploration Ltd., a wholly owned unit of Inpex, will hold and manage the interest.

Inpex will receive the opportunity to develop and produce any commercial discoveries during a production phase in which ADNOC has the option to back in for a 60% stake.

Block 4 is the fourth concession awarded in Abu Dhabi’s first competitive bid round, which offered six blocks (OGJ Online, Feb. 4, 2019).

Ukraine announces second, third licensing rounds

Ukraine outlined terms for its second and third licensing rounds. Bidding will be done using an online auction for areas covering more than 2,260 sq km. Licensing rounds are being offered in stages (OGJ, Mar. 4, 2019, p. 31).

Separately, Ukraine said an earlier first licensing round has resulted in the awarding of licenses for three blocks. Seven other blocks attracted no bids. The total amount was more than $5.2 million. Three Ukraine gas producers received the licenses: Burisma Group, Block 2, DTEK Oil & Gas, Block 3, and state-owned UkrGasVydobuvannya (UGV), Block 7.

Second-round terms call for participants to be Ukrainian legal entities although they can be controlled by a nonresident company. The bidder is mandated to pay the guarantee fee at 20% of the initial price of the bid.

Ukraine launched a third round on Mar. 18 for nine onshore blocks in three regions. All third-round licenses are for 20-year periods. Bids are to be submitted by June 18.

In addition, the Ukrainian government has opened a public tender for nine blocks under a production-sharing agreement covering 11,600 sq km. Interested parties must submit applications by May 28. Winning bidders will be notified by June.

Qatar Petroleum due interest off Morocco

Qatar Petroleum has agreed to acquire a 30% participating interest from Eni in the Tarfaya Shallow Exploration Permit along Morocco’s Atlantic coast. The permit encompasses 12 blocks covering 23,900 sq km in water as deep as 1,000 m.

The first exploration phase involves geological and geophysical studies aimed at defining prospects. It ends in 2020.

The agreement is subject to approval by the Moroccan government. Other interests after the farmout will be Eni, operator, 45%, and the National Office of Hydrocarbons and Mines, 25%.

Drilling & ProductionQuick Takes

Iran commissions four South Pars phases

Iran has commissioned four more phases of offshore South Pars natural gas field. Phases 13 and 22-24 have production capacities of 56 million cu m/day, 75,000 b/d of condensate, and 400 tonnes/day of sulfur each.

At an inauguration event in Assaluyeh, Minister of Petroleum Bijan Zangeneh said start-up of the phases, in which Iran has invested $11 billion, boosted South Pars production to more than that of supergiant North field, as the Qatari part of the reservoir is known. The start-ups bring to 22 the number of operational South Pars phases.

Vision 2035 goals to cost E&P firms $265 billion

Oil & Gas UK estimates exploration and production companies would have to spend about $265 billion between 2019-35 to realize industry’s expectations outlined in Vision 2035 on the UK Continental Shelf (UKCS).

Vision 2035 is a framework for the UKCS led by Oil & Gas UK and the Oil & Gas Authority. An Oil & Gas UK business outlook said pretax E&P expenditure on the UKCS was about $19 billion in 2018. Pretax E&P expenditures are expected to increase to more than $19.8 billion in 2019.

The report shows UKCS production was about 619 million boe in 2018. This figure marked a 4% increase on 2017 and a 20% rise over the previous 5 years, the report said.

Despite low 2018 drilling activity, industry found an estimated 485 million boe in 2018. More new projects were approved in 2018 than the previous 3 years combined and 15 exploration wells are expected to be drilled this year.

Oil & Gas UK Chief Executive Officer Deirdre Michie urged suppliers and operators to collaborate to improve costs. “Our report finds an industry that’s getting better at what it does,” Michie said. “However, challenges remain across parts of the supply chain with revenues and margins still under pressure.”

UK oil, gas, liquids output up 4% in 2018

Production of oil, natural gas, and natural gas liquids increased in the UK by 4% in 2018 to an average of 1.7 million boe/d, according to the UK Oil and Gas Authority (OGA).

Oil production alone increased 8.9% from 2017 to 1.09 million b/d, the UK’s highest rate since 2011.

Gas production fell by 2.5% to 610,000 boe/d.

In an update of a March 2015 estimate, OGA projected cumulative oil, gas, and gas liquids production during 2016-50 of 11.9 billion boe, up 3.9 billion bbl from the earlier assessment.

OGA said total oil and gas operating costs rose by 6.4% last year to £7.2 billion.

Unit operating costs rose by 2.2% to £11.6/boe.

Capital expenditure on UK oil and gas fell for the fourth straight year. OGA projects a 4% increase this year.

Decommissioning outlays jumped 9% in 2018 to £1.45 billion.

Imperial’s Aspen oil sands project delayed by a year

Imperial Oil Ltd. said its recent decision to slow development of its Aspen in situ oil sands project will delay the project’s expected production start by at least a year given the limited winter drilling and site preparation season (OGJ Online, Nov. 7, 2018). The decision to slow activity was made given market uncertainty stemming from Alberta government intervention and other industry competitiveness challenges.

Work done this year will enable the company to resume planned activity levels “when the time is right,” said Rich Kruger, chairman, president, and chief executive officer. “A decision to return to planned project activity levels will depend on subsequent government actions related to curtailment and the company’s confidence in general market conditions,” he said.

Final investment decision to develop the $2.6-billion (Can.) project 45 km northeast of Fort McMurray, Alta.—expected to produce 75,000 b/d of bitumen with the potential for further development of as much as another 75,000 b/d of bitumen—was made in November 2018.

Chevron lets contract for Jansz-Io compression project

Chevron Australia has let a master contract to Aker Solutions for a subsea compression system for the company’s Jansz-Io field offshore Western Australia.

The first stage of the contract is the front-end engineering and design of a subsea compression station that will boost gas recovery at the field, which is part of the overall Gorgon region development that supplies gas to the 15.6 million-tonne/year LNG and domestic gas plants on Barrow Island.

The FEED scope also includes an unmanned power and control floater along with overall field system engineering services. Aker said the field control station will distribute onshore power to the subsea compression station.

The company added that the new subsea gas compression system will improve gas recovery more cost-effectively and with a smaller environmental footprint than a conventional semisubmersible compressor station. The idea is to help maintain plateau gas production rates as the natural reservoir pressure drops over time. Jansz-Io field lies 200 km off northwestern Western Australia. The compression project is part of the original development plan for the overall Gorgon project.

Aker Solutions pioneered subsea compression when it delivered the world’s first subsea system for Equinor’s Asgard field in the North Sea offshore Norway in 2015.

Cooper completes phase of Sole field development

Cooper Energy Ltd., Adelaide, has completed the offshore construction phase of its wholly owned Sole gas field development in Bass Strait. The company said installation and testing of the 67-km control umbilical connecting the field’s two subsea production wells to the onshore processing plant near Orbost on the east Gippsland coast was finalized earlier this month.

There is still work remaining to repair a damaged section of the subsea pipeline, but this will be done in April so that the $355-million (Aus.) offshore project will be completed, ready, and available to deliver gas to the APA Group’s Orbost plant by the end of May.

APA’s $250-million (Aus.) upgrade of the gas plant to process Sole production is slated for completion during this year’s third quarter, although gas is expected to be introduced to the system prior to plant completion for commissioning and subsequent plant performance tests.

Sole field lies in about 65 km offshore on retention lease Vic/RL3 in 124 m of water. The field will supply about 24 petajoules/year of gas with about 75% of the field’s reserves contracted to a range of utility and industrial customers including AGL Energy, EnergyAustralia, Alinta Energy, and O-I.

Gas will be delivered from the Orbost plant into the Eastern Gas Trunkline, which extends up Australia’s east coast to Sydney.

Sole field was originally discovered by Shell Australia in 1973, but deemed subcommercial, especially since there are no liquids present with the gas. The field subsequently changed hands many times until Cooper Energy became 100% owner when the company bought Santos Ltd.’s 50% share in fall 2016 (OGJ Online, Oct. 24, 2016).

Spirit starts production from Oda field in North Sea

Spirit Energy Ltd. and its partners started oil production from Oda field, which lies in 65 m of water 13 km east of Ula in production license 405 in the North Sea, on Mar. 16, about 5 months ahead of schedule.

Spirit’s plan for Oda, which was approved in 2017, calls for development via a subsea facility including two production wells tied back to Ula field for processing and one injection well for pressure support (OGJ Online, Nov. 30, 2016). Oil is exported to Ekofisk and then carried by Norpipe to the UK’s Teesside terminal. Gas from Oda is injected into the Ula reservoir to improve oil recovery from that field. The processing equipment and hook-up to the Ula platform are reused from the shutdown Oselvar field.

Discovered in 2011 via well 8/10-4S, Oda’s main reservoir contains oil in sandstone of Late Jurassic age in the Ula formation. The reservoir, 2,900 m subsea, is steeply dipping and quality is good. Prior to start-up of the Oda project, Spirit Energy entered into long-term contracts with four supplier companies: Aibel, Subsea 7, TechnipFMC, and DNV GL. Oda’s recoverable reserves are estimated at about 33 million boe, of which 95% is oil. Peak production is expected to reach nearly 35,000 b/d.

PROCESSINGQuick Takes

Hungary’s MOL lets contract for Duna refinery

Hungary’s MOL Group has let a contract to Frames Group BV, Alphen aan den Rijn, the Netherlands, to provide desalting equipment for subsidiary MOL PLC’s 166,500-b/d Duna refinery in Szazhalombatta, near Budapest.

As part of the contract, Frames will supply two of its proprietary desalters (electrostatic coalescers) to be installed in the refinery’s crude distillation unit as part of a new project to enable the site to process a broader range of crudes, the service provider said.

The desalters’ two-phase separators use an electrostatic field to remove water and salts from crude oil to protect downstream processes from unwanted corrosion and fouling.

The new crude desalting system comes as part of the operator’s program of crude basket diversification, increasing its current alternative seaborne crude intake to above 33% and allowing the processing of more than 50 additional crude grades, Frames said.

The contract award—for which no value was disclosed—follows an optimization study focused on identifying shortcomings of the refinery’s existing desalters as well as other changes to be implemented at the site to enable the refinery to handle more complex and challenging blends, the service provider said.

PetroChina commissions unit at Jilin refinery

PetroChina Co. Ltd.—the publicly listed arm of state-owned China National Petroleum Corp. (CNPC)—has started up an alkylation unit at its 200,800-b/d refinery in Jilin City, Jilin Province, China. The 9,000-b/d unit reached commercial startup and production just 17 months following initial design, McDermott International Inc. (formerly CB&I) said. The unit is based on McDermott’s proprietary CDAlky advanced sulfuric acid alkylation process technology and is now the single largest CDAlky reactor to date.

The Jilin unit is the first of four previously announced CDAlky units for PetroChina to reach startup, with additional units also to be implemented at PetroChina subsidiaries Dalian Petrochemical Co.’s 411,700-b/d Dalian refinery and Jinzhou Petrochemical Co.’s 140,600-b/d Jinzhou refinery, both in Liaoning province, as well as at Urumqi Petrochemical Co.’s 100,400-b/d Urumqi refinery in Xinjiang Uygar Autonomous Region (OGJ Online, Aug. 28, 2017).

The new CDAlky units come as part of PetroChina’s plan to produce lower-sulfur, higher-octane, alkylate to ensure compliance of gasoline and diesel production with more stringent global emission standards, including China 6-quality specifications (equivalent to Euro 6 specifications), which will cap the maximum sulfur content of fuels at 10 ppm beginning in 2020.

Chinese firm lets contract for propylene plant

Jiangsu Sailboat Petrochemical Co. Ltd., a subsidiary of ShengHong Petrochemical Group Co. Ltd., has let a contract to Honeywell UOP LLC to provide process technology for a project to increase propylene production at its existing operations in Lianyungang City in China’s province of Jiangsu.

As part of the contract, Honeywell UOP will provide licensing for its proprietary C3 Oleflex process technology, the process design package, equipment, on-site operator training, technical services, as well as catalysts and adsorbents for the project, the service supplier said.

Part of an expansion of Jiangsu Sailboat’s olefins complex—which currently uses Honeywell UOP’s proprietary methanol-to-olefins process to produce ethylene and propylene—the new unit, once completed, will increase polymer-grade propylene production at the site by 700,000 tonnes/year and overall output of short-supply, high-end petrochemical products to more than 2.5 million tpy.

TRANSPORTATIONQuick Takes

Venture Global to expand LNG business

Venture Global LNG Inc., Arlington, Va., will expand the scope of its LNG development business to 60 million tonnes/year based on customer demand, expanding its 2016 process equipment supply agreement with Baker Hughes.

The agreement provides for the supply of modular liquefaction trains plus power generation and electrical distribution equipment that will be standardized across the company’s Calcasieu Pass, Plaquemines LNG, and other expansion projects.

The 10 million-tonne/year Calcasieu Pass project has received all federal authorizations and the project’s EPC contractor, Kiewit Construction Co., plans to begin site activities soon (OGJ Online, Mar. 6, 2019). Under 20-year agreements with Shell, BP, Edison SPA, Galp, Repsol, and PGNiG, Calcasieu Pass will begin delivering US gas to the global market in 2022.

The 20-million tonne/year Plaquemines LNG project is expected to receive its final authorization from the US Federal Energy Regulatory Commission in August and start construction this year.

FERC issues final EIS for Brownsville LNG project

Construction of Texas Brownsville LNG LLC’s proposed LNG project could result in adverse environmental consequences, the US Federal Energy Regulatory Commission said in a Mar. 15 final environmental impact statement. Impacts would be less than significant if the project sponsor’s proposed impact avoidance, minimization, and mitigation measures and the FERC staff’s additional recommendations are implemented.

But the project’s construction, in addition to two others proposed in the area, would result in substantial cumulative impacts from sediment and turbidity and shoreline erosions within the Brownsville Ship Channel during operations from vessel transits, the final EIS warned. Habitat for the federally listed aplomado falcon, ocelot, and jaguarundi also could be lost, and vessels could strike the animals, it said.

Commonly called the Texas LNG Project, the facility’s terminal would be built in an area currently zoned for commercial and industrial use, along an existing, manmade ship channel, FERC’s final EIS said. It indicated that the project’s sponsor filed plans outlining spill-prevention controls, stormwater-pollution prevention, noxious weed and invasive plant controls, facility lighting, migratory bird protection, terrestrial reptile and amphibian conservation, the discovery of unanticipated cultural resources, and fugitive dust controls.

FERC’s final EIS is the last step in the environmental review process leading toward the June 13 authorization decision deadline and anticipated issuance of final FERC approval.