GENERAL INTEREST Quick Takes
Equinor to increase gas exports to supply tight European market
Equinor Energy AS and partners received permission to increase gas exports from two fields on the Norwegian continental shelf to supply the tight European market.
Production permits for Oseberg and Troll fields have each been increased by 1 billion cu m (bcm) for the gas year started Oct. 1.
In June, the operator took steps to evaluate and develop concepts for enhancing production and exports to the European market, which resulted in enhanced production permits from the Ministry of Petroleum and Energy for the fields.
Specifically, Equinor and partners received production permits for the gas year 2021 which for each is 1 bcm higher than for the current year. Oseberg increases to 6 bcm from 5 bcm and Troll increases to 37 bcm from 36 bcm.
After 25 years of significant gas exports from Troll in the North Sea, about 50% of the gas is left in the ground, Equinor said. Troll Phase 3 started production Aug. 27 to further develop the area (OGJ Online, Aug. 30, 2021).
Recoverable volumes from Troll Phase 3, which will produce the Troll West gas cap, are estimated at as much as 347 billion standard cu m of gas. Total recoverable gas volume remaining in Troll is estimated at 715 billion standard cu m.
Troll Phase 3 will extend the life of Troll A and the Kollsnes processing plant beyond 2050, and the plateau production period by 5-7 years.
Fundare closes acquisition of Redtail assets from Whiting
Fundare Resources Co. LLC, Denver, on Nov. 1 will take over operations of oil and gas assets in the Denver-Julesburg basin of Colorado (Redtail assets) it acquired from Whiting Petroleum Co.
In July, Whiting noted an agreement with a then-undisclosed buyer to divest its Redtail assets in rural Weld County, including associated midstream assets, for total cash consideration of $187 million (OGJ Online, July 22, 2021). The assets span 67,278 net acres (99% operated) with 319 operated wells producing 7,100 boe/d (51% oil, 70% liquids), and include a wholly owned natural gas processing plant with capacity of 65 MMcfd and 100 miles of gathering pipelines
The acquisition was funded through equity provided by WDC Energy LLC, management, and a group of friends and family investors, Fundare said. The company also entered into a note purchase agreement with Cibolo Energy Partners LLC to provide debt capital used to fund a portion of the acquisition.
East Timor extends oil and gas licensing round a second time
East Timor has extended the deadline for its onshore and offshore oil and gas licencing round for a second time in
an effort to capture interest from international and national oil companies.
The country’s resources regulator, Autoridade Nacional do Petroleo e Minerais (ANPM), said the deadline for submission of bids has moved to Mar. 4, 2022, from Oct. 1, 2021.
The round, which offers a total of 18 blocks for public tender for production sharing contracts (seven onshore and 11 offshore in the Timor Sea), was originally launched Oct. 19, 2019, with a deadline for submissions on Oct. 9, 2020. The deadline was then extended to Oct. 1, 2021.
ANPM said the global COVID-19 pandemic has interfered with its plans to promote the licencing round during the last 2 years. The extension will provide more time for interested parties to carry out internal studies and technical assessments prior to the submission of bids, it said.
The new timetable also provides extra time for submission of pre-qualification documents. This is now due on or before Jan. 14, 2022. The round will be open for bid submissions for 2 months from Jan. 24, 2022.
This is East Timor’s second licencing round. The first was held in 2005-2006. The subsequent round was delayed due to the territorial dispute with Australia in the Timor Sea which was resolved in August 2019.
Terms of the second round do not require a signature bonus and general terms call for full cost recovery, 5% royalty, 60-40 profit split in favor of operators, and 30% income tax.
Exploration & Development Quick Takes
Shell submits PDO for Ormen Lange subsea compression
A/S Norske Shell and partners have taken a final investment decision on a wet gas subsea compression project at the Ormen Lange gas and condensate field in the Norwegian Sea and submitted a plan for development and operation (PDO) to the Ministry of Petroleum and Energy.
Two stations with compressors that handle rich gas will be installed on the seabed near the wellheads at 900 m sea depth. The project is designed to produce another 30-50 billion cu m natural gas, increasing field recovery rate of 75-85%. The distance between land and seabed compressors will be a new length record for power cable for compressors under water.
Ormen Lange, in the Norwegian Sea, is electrified with power from the Norwegian power grid, and the gas is processed in a closed system at Nyhamna gas plant. The field exports its gas through Langeled, a 1,200 km long pipeline from Nyhamna to Easington, UK. Langeled is also linked to the Norwegian gas export system to Europe.
In 2019, OneSubsea was awarded the frame agreement for an Ormen Lange subsea multiphase compression system (OGJ Online, Nov. 1, 2019).
OneSubsea has contracted Subsea 7 to engineer, procure, construct, and install the subsea flowline system as well as install the multiphase compression system. This will be executed as a Subsea Integration Alliance project.
Shell is operator at Ormen Lange (17.8%) with partners Petoro AS (36.4%), Equinor Energy AS (25.3%), INEOS E&P Norge AS (14%), and Vår Energi AS 6.3%.
Touchstone finds hydrocarbons in Ortoire exploration
Touchstone Exploration Inc. encountered hydrocarbon accumulations in the Royston-1 exploration well on the Ortoire block, onshore in the Republic of Trinidad and Tobago.
The well, the fifth and final well of the first phase of exploration drilling program on the block, spudded on Aug. 12 using Well Services Petroleum Ltd. Rig #60 and was drilled to a total depth of 10,700 ft. It is the deepest exploration well drilled by Touchstone to date.
The well was designed to explore a thick sequence of Herrera sandstones contained in an overthrust sheet which was observed in the offsetting OL-4 well drilled by Shell Trinidad Ltd. in 1965. Primary targets of the well were Gr7a and Gr7bc Herrera sands in an upper thrust sheet at about 9,700 ft. The well was designed to penetrate the Herrera section observed but not tested in OL-4 at a structurally optimized position based on legacy and new seismic data. It was drilled about 300 ft deeper to investigate a lower thrust sheet identified by Touchstone’s subsurface team.
The well encountered total Herrera turbidite thickness of 1,014 ft (609 ft net sand) in two stacked thrust sheets. An aggregate 393 gross ft of hydrocarbon pay was identified in the sheets from 9,700 ft to total depth, with wireline logs indicating that the well was in hydrocarbon pay at total depth.
About 30 ft of hydrocarbon pay was detected in the shallow Lower Cruse formation, and 30 ft of pay was noted in the Karamat Gr7a sands. Based on wireline logs, the well was hydrocarbon charged at the well’s total depth of 10,700 ft.
The well is currently being cased and prepared for production testing of the Herrera formation.
Touchstone has 80% working interest in Ortoire block but is responsible for 100% of the drilling, completion, and testing costs associated with the initial five exploration wells. Heritage holds the remaining 20% working interest.
Eni, partners start up Cabaça North development offshore Angola
Eni started production from the Cabaça North development project in Block 15/06 offshore Angola via the Armada Olombendo FPSO.
The development, with an expected peak production rate of 15,000 b/d of oil, will increase and sustain the plateau of the Armada Olombendo, a zero-discharge, zero-process flaring FPSO with an overall capacity of 100,000 b/d, the operator said in a release Sept. 24.
This is the second start-up by Eni Angola this year following Cuica Early Production achieved in July. A third start-up is expected within the next few months, with the Ndungu Early Production in the western area of Block 15/06.
Eni Angola operates Block 15/06 with 36.84% interest. Partners are Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Ltd. (26.32%).
Aker BP to tie back Frosk field to Alvheim FPSO
Aker BP ASA and partners submitted a plan for development and operation (PDO) for Frosk field development to the Norwegian Ministry of Petroleum and Energy.
The field, in an injectite sandstone reservoir in North Sea license PL340 about 25 km southwest of the Alvheim FPSO, will be developed via tieback to existing Bøyla and Alvheim subsea infrastructure. Production is scheduled to start in first-quarter 2023.
Two new production wells will effectively drain the field. The project has matured over the 2 years since test production commenced, and the tieback will fast-track development, the operator said.
An alliance of Aker BP, Odfjell Drilling, and Halliburton will drill and complete the new wells, and an alliance of Aker BP, Subsea 7, and Aker Solutions will execute the subsea workscope.
Total investments will be around NOK 2 billion (about $230 million). Recoverable reserves in Frosk are estimated at around 10 MMboe.
Alvheim field consists of Kneler, Boa, Kameleon, and East Kameleon structures. Viper-Kobra and Gekko structures also reside within the license. The Kobra East and Gekko (KEG) development is expected to come on stream 1 year after Frosk.
Alvheim area also includes satellite fields Bøyla, Vilje, Volund, and Skogul. All are produced via the Alvheim FPSO, which came on stream in June 2008.
When the Alvheim development was originally sanctioned, recoverable resources from the field were estimated at close to 200 million bbl. Since then, more than 500 million bbl have been produced from the area, the operator said.
Aker BP is operator at Frosk (65%) with partners Vår Energi AS (20%) and Lundin Energy Norway AS (15%).
Drilling & Production Quick Takes
bp starts production from Thunder Horse expansion
bp has begun production from its Thunder Horse South expansion Phase 2 project, advancing the operator’s plan to grow its Gulf of Mexico oil and gas production to around 400,000 boe/d (net) by the mid-2020s.
The expansion project—in Mississippi Canyon block 822, southeast of the Thunder Horse platform in 6,350 ft of water—is expected to increase output at Thunder Horse field, with peak annual average gross production of 25,000 boe/d from the initial two well tie-back, the operator said in a Sept. 28 release.
Eventually a total of eight wells are expected to be drilled as part of the project’s overall development.
Thunder Horse, bp’s largest production and drilling platform in the Gulf, lies 150 miles southeast of New Orleans, La. It is designed to process up to 250,000 boe and 200 million cu ft of natural gas per day. bp holds a 75% working interest. ExxonMobil holds the remaining 25%.
The project consists of two subsea drill centers operated by 10-in. dual flow lines with the opportunity for simultaneous Mobile Offshore Drilling Unit (MODU) operations.
Thunder Horse South expansion Phase 2 completes the program of five major project start-ups planned for 2021. Together with the early start-up of the Matapal project in Trinidad, six major projects have come on stream for bp this year.
In the deepwater Gulf of Mexico, bp operates four production platforms—Thunder Horse, Atlantis, Mad Dog, and Na Kika—with a fifth platform, Argos, expected to come online in 2022.
Norway production increased in August, NPD says
Norway’s liquids production averaged 2.114 million b/d in August, the Norwegian Petroleum Directorate reported Sept. 23.
Norway’s liquids production averaged 2.035 million b/d in July (OGJ Online, Aug. 19, 2021).
Oil production in August is 3% higher than NPD’s forecast, and 0.7% higher than the forecast so far this year.
The average daily liquids production in August consists of 1.812 million b/o, 292,000 bbl of NGL, and 10,000 bbl of condensate.
The total petroleum production for the first 8 months in 2021 is about 151.9 million standard cu m oil equivalents.
Lockyer Deep-1 gas discovery exceeds pre-drill expectations
The Energy Resources Ltd. and Norwest Energy NL joint venture onshore North Perth basin of Western Australia has confirmed the high quality of its gas discovery in the Lockyer Deep-1 wildcat in permit EP 368.
The JV completed wireline logging operations and petrophysical analysis of the data confirms a 34 m gross pay interval at the top of the Kingia Sandstone reservoir between 3,888 m and 3,922 m with gas interpreted down to low permeability. Based on an 8% porosity cutoff, net gas pay within this interval is 20.2 m.
The net pay zone has an average porosity of 16% and an average permeability estimated at 500 millidarcies. Maximum measure porosity is 28%.
Reservoir pressure at the top of the pay interval is 6,514 psi.
A well-defined gas gradient was measured through the pay interval which, when combined with the regional water gradient, indicates the presence of a gas column of up to 800 m from the nearby North Erregulla crestal location down to a free water line at about 4,500 m, Norwest said.
The company said this confirms the fault-seal integrity of the structure’s main bounding faults, regardless of orientation and despite a significant gas column.
Petrophysical analysis of other potential pay zones is also complete. The High Cliff Sandstone section has been deemed to be of generally low porosity and permeability and not expected to offer conventional gas pay at the Lockyer Deep-1 location.
The Dongara-Wagina section contains a gross oil column of 66 m of which 30 m has an average porosity of 9% with permeability generally low. Further analysis is needed.
Lockyer Deep-1 is being completed for production testing in the Kingia Sandstone.
The JV also is preparing for a 3D seismic survey across the greater Lockyer Deep-North Erregulla Deep structure.
Energy Resources is operator with 80% interest. Norwest holds the remaining 20%.
PROCESSING Quick Takes
LOTOS lets contract for new plant at Gdan´sk refinery
Grupa LOTOS SA has let a contract to a division of Maire Tecnimont SPA to provide engineering, procurement, and construction (EPC) services for a grassroots hydrocracking plant to expand production of base oils at its 10.5-million tonnes/year refining complex in Gdan´sk, Poland.
As part of the September lump-sum turnkey EPC contract, Maire Tecnimont subsidiary KT-Kinetics Technology will deliver the full scope of EPC services for the new hydrocracked base oils (HBO) plant and associated logistic installations to enable production and sale of high-quality Group 2 and Group 3 base oils, the service provider and Grupa LOTOS said.
Scheduled to be fully completed and operational during first-half 2025, the HBO plant will be equipped to produce base oils meeting the automotive sector’s increased demand for low-sulfur, energy-efficient fuels in line with increasingly more stringent international environmental regulations, as well enable the refinery to improve economics of its overall crude processing activities, according to Grupa LOTOS and Maire Tecnimont.
The service provider valued the EPC contract, which was awarded on a lump-sum turnkey basis, at slightly more than €200 million.
In a July 2021 presentation to investors, Grupa LOTOS said the project—at the time, still in its planning phase—would require an overall investment of 1.378 billion zloty, 206 million zloty of which was scheduled to be spent during 2021.
Alongside allowing the refinery to produce high-margin Group 2 and Group 3 base oils, the new HBO plant will contribute to the operator’s goal of efficiently managing residues from the refinery’s mild hydrocracking unit—specifically, hydrowax—as well as contribute to its broader goal of diversifying its production mix to new and nonfuel products, according to Grupa LOTOS’ yearend-2020 annual report to investors.
TRANSPORTATION Quick Takes
Enbridge completes Line 3 replacement
Enbridge Inc. has substantially completed its Line 3 Replacement Project, setting an in-service date of the first week of October. The new 337-mile Minnesota segment of Line 3 restores full capacity to 760,000 b/d.
The Minnesota segment of the crude oil pipeline used 36-in. OD pipe to replace 282 miles of the existing 34-in. line installed in the 1960s. Completion of work in Minnesota marks full replacement of the entire 1,097-mile pipeline from Edmonton, Alta. to Superior, Wisc.
The 14-mile Wisconsin segment of the project entered service May 2018. The 13-mile North Dakota segment was completed December 2020, at which point Enbridge began construction in Minnesota.
Enbridge had been operating the line at 390,000 b/d since 2008, cutting pressure to mitigate the possibility of leaks.
PennEast cancels Pennsylvania-NJ gas pipeline project
PennEast Pipeline Co. LLC has cancelled development its proposed 120-mile, 1.1-bcfd natural gas pipeline from Pennsylvania to New Jersey. PennEast cited outstanding permits—including a water quality certification from the State of New Jersey—as having motivated the cancellation.
The project was halted despite the company having earlier this year won a US Supreme Court verdict allowing it to use eminent domain to seize state-controlled land in New Jersey for purposes of building the pipeline.
Environmental groups lauded the cancellation as a victory, noting that 74% of the pipeline’s contracted takeaway capacity consisted of agreements between its developers and affiliate companies. But Interstate Natural Gas Association of America president and chief executive officer Amy Andryszak said in response to the cancellation that “Natural gas is foundational to meeting President Biden’s climate change goals, but that requires the ability to transport that fuel from where it is produced to where it is needed. Natural gas has proven itself a versatile, baseload energy source that enables power sector emissions reductions and complements the deployment of renewables while ensuring energy remains reliable. The legal and regulatory roadblocks that led to the cancellation of the PennEast Pipeline – which would have been built with union labor – are putting energy affordability and reliability at risk in America.”
PennEast was approved by the US Federal Energy Regulatory Commission (FERC) in 2018 and the company expected it to enter service the following year, but protests against it began almost immediately. Democrat Commissioner Richard Glick dissented from the approval, citing both a lack of need for the pipeline and FERC’s refusal “to consider the consequences its actions have” on climate change according to Natural Gas Act and Natural Environmental Policy Act requirements.
Beach Energy, BP sign Waitsia LNG agreement
Beach Energy Ltd. has entered a heads of agreement with BP Singapore Pte Ltd. for BP to purchase 3.75 million tonnes of LNG from Beach, sourced from the Waitsia gas development onshore North Perth basin in Western Australia.
The supply is expected to begin during second-half 2023 and continue for 5 years. The supply represents all of Beach’s expected LNG volumes from Stage 2 of the Waitsia gas project.
Gas from Waitsia will be piped north to the North West Shelf gas processing infrastructure on the Burrup Peninsula near Karratha and will be the first third party gas supply into the North West Shelf LNG plant.
LNG will be delivered on a free-on-board basis from the Burrup infrastructure where BP is joint venture participant.
The LNG price has not been disclosed, but is linked to both Brent and Japan Korea marker price indices and includes a downside price protection mechanism.
Beach is a partner in the Mitsui-operated, 50-50 joint venture Waitsia project. The field is rated as one of the largest gas fields discovered onshore Australia.
Waitsia Stage 2 is a US$750-800 million project that involves further development to produce around 760 bcf of gas at a rate of 250 terajoules/day.
In August 2020, the project was granted an exemption from the Western Australian Government’s domestic gas reservation policy which enables up to half of the Waitsia production to be exported as LNG via the North West Shelf infrastructure.
Beach and BP aim to execute a fully termed LNG supply and purchase agreement in the second half of the 2022 financial year.
