GENERAL INTEREST Quick Takes
Romgaz to buy ExxonMobil Romanian affiliate for $1 billion
SNGN Romgaz SA, the largest natural gas producer in Romania, has reached a deal with ExxonMobil to purchase its Romanian upstream affiliate, ExxonMobil Exploration and Production Romania, for more than $1 billion, subject to Romanian government approvals.
The agreement includes all shares in ExxonMobil Exploration and Production Romania along with its 50% interest in the deepwater XIX Neptun block in the Black Sea. Operatorship of the block will transfer to the remaining partner, OMV Petrom. Employees of the Romanian affiliate will transfer as part of the deal, ExxonMobil said in a May 3 release.
With the contract signed, steps to close the deal—expected in this year’s second quarter—will follow, after which, together with OMV Petrom, Romgaz will work to transition gas fields in the Neptun Deep perimeter to the development-exploitation phase with the aim of first production end 2026 or early 2027, said Aristotel Jude, Romgaz General Manager, in a signing ceremony May 3.
ExxonMobil acquired the Neptun Deep block interest in 2008, forming a joint venture with OMV Petrom. The 7,500-sq km block lies in water depths of 100-1,700 m.
More than 3,000 sq km of 3D seismic data was acquired over the block, and in March 2012, Domino-1, the first deepwater well in Romania, confirmed the presence of natural gas (OGJ Online, Feb. 2, 2012). In 2016, OMV Petrom completed an exploration drilling campaign which included seven wells (OGJ Online, May 6, 2016). Commercial viability of the resource is ongoing.
Continental Resources raises production guidance, capital program
Continental Resources Inc., Oklahoma City, has increased its 2022 annual oil production guidance to 200,000-210,000 b/d from 195,000-205,000 b/d inclusive of production from a completed deal to acquire Wyoming Powder River basin assets from Samson Resources II LLC (OGJ Online, Mar. 15, 2021).
The company is projecting a December 2022 oil production exit rate of about 220,000-230,000 b/d and updating its 2022 annual natural gas production guidance to 1,100-1,200 MMcfd from 1,040-1,140 MMcfd.
The update projected first-quarter total production averaged 373,800 boe/d (oil production of 194,800 b/d and natural gas production of 1,074 MMcfd).
A modified 2022 capital program of $2.6-2.7 billion from $2.3 billion is expected to increase the company’s projected return of capital employed by 2% over its original 21% at $80 WTI and $3.50 Henry Hub. The increase is on the heels of a 47% spending increase in February (OGJ Online, Feb. 22, 2022). Adjusting for current commodity prices, the projected return on capital employed is increasing to about 31% in 2022.
Continental is projecting a 40% or lower reinvestment rate, versus about 45% in the original capital program. Within the modified spend, the company is allocating $100-125 million to activity related to a newly closed bolt-on acquisition in the Permian. The company added over 75,000 acres to its Permian basin position in addition to its $3.25-billion entrance deal with Pioneer Natural Resources in November 2021 (OGJ Online, Nov. 4, 2021). In a February investor presentation, the company noted planned 2022 drilling and completion spend for Permian assets of $400 million, with 46 total net wells and an average of 4 rigs running.
In the update ahead of the earnings call, Continental noted $100-150 million is earmarked to outside operated spending. Some $100-125 million is expected to go toward inflation and securing quality rigs and crews for future years.
ConocoPhillips makes executive leadership changes
ConocoPhillips has appointed Tim Leach, previously executive vice-president, Lower 48, to advisor to the chief executive officer, effective May 1. He will continue to serve as a member of the company’s board of directors.
Jack Harper, previously president, Permian for ConocoPhillips, has assumed the role of executive vice-president, Lower 48, and joined the executive leadership team, effective May 1. Harper has more than 25 years of experience leading operations, finance, corporate planning/strategy, capital markets, and business development functions.
ConocoPhillips acquired Concho Resources in an all-stock deal worth $13.6 billion, including debt, in 2020 (OGJ Online, Oct. 19, 2020). Leach and Harper both joined ConocoPhillips with the acquisition in 2021. Leach had served as chairman of the board and chief executive officer of Conco Resources, and Harper was president.
Exploration & Development Quick Takes
Neptune confirms Hamlet discovery, extended potential of Agat play
Neptune Energy has initiated studies to consider development options for Hamlet (PL153) in the Norwegian sector of the North Sea following confirmation of an oil and gas discovery and the extended potential of the Agat play.
A further exploration well (Ofelia prospect) at Agat—previously only developed and produced in Neptune-operated Duva field—will be drilled later this year, said Steinar Meland, Neptune’s director of exploration and development in Norway.
At the Hamlet structure, in-place volumes are estimated to be 5-11 million standard cu m (30-70 MMboe). Work is continuing to confirm potential recoverable resources, but Neptune’s preliminary estimate is 8-24 MMboe.
Hamlet lies 58 km west of Florø, Norway, at a water depth of 358 m. It will be considered as a tie-back to the Neptune-operated Gjøa semisubmersible platform.
Hamlet is a new discovery in the Gjøa area, where Neptune operates two fields. Wintershall Dea-operated Vega and Nova fields are also tied back to Gjøa platform.
The drilling program comprised a main-bore (35/9-16S) with a sidetrack (35/9-16A). Both wells found hydrocarbons, and the sidetrack confirmed an oil-water contact at 2,662 m total vertical depth.
Hamlet was drilled by the Deepsea Yantai, a semisubmersible rig, owned by CIMC and operated by Odfjell Drilling.
Neptune is operator at Hamlet with 30% interest. Partners are Petoro 30%, Wintershall Dea 28%, and OKEA 12%.
BW Energy advances Maromba field development, acquires FPSO
BW Energy Co. will proceed with the Maromba development project, offshore Brazil, and has agreed to purchase the Polvo FPSO from BW Offshore Ltd. for $50 million.
Development is based on an initial drilling campaign of three wells with planned first oil in 2025 and a second campaign with a further three wells in 2027. Total oil production of 30-40,000 b/d is expected at peak.
Staged development enables improved reservoir monitoring and optimization of the second drilling campaign, the company said. The technical evaluation revealed that water injection is not required for the first three wells and is a contingency for the second drilling campaign. Extensive work has also confirmed that dual electric submersible pumps offer the best artificial lift solution with extended life and reduced workover frequency. The subsea layout has also been enhanced to reduce costs and facilitate future expansions, the company continued.
The FPSO recently ended its charter on Polvo field and will be upgraded and redeployed at Maromba. An assessment of refurbishment costs has been completed and discussions with relevant shipyards are under way. The FPSO will be designed for up to 10 production wells with 1.2 million bbl storage capacity. Total liquid capacity will be 85,000 b/d with oil production capacity of 65,000 b/d and water treatment capacity of 75,000 b/d.
Maromba is in Campos basin in about 160 m of water. Nine wells were drilled in the license between 1980 and 2006, and oil was found in eight across various reservoirs. Gross 2C reserves in place are estimated at 467 million bbl with about 100 million bbl estimated as recoverable volumes.
BW Energy is operator at Maromba and has 100% ownership.
Central Petroleum begins Amadeus basin exploration program
Central Petroleum Ltd., Brisbane, has spudded the Palm Valley 12 (PV12) well in OL3, southwest of Alice Springs in the Northern Territory.
The well is the first of a two-well drilling program that also includes the Dingo-5 exploration/production well. Central holds 50% interest in PV12 and Dingo-5, which are free-carried for Central by New Zealand Oil & Gas (35%) and Cue Energy Resources (15%) and are scheduled to be completed this year (OGJ Online, May 31, 2021).
PV12 has two alternative objectives, consisting of a deeper gas exploration target or a shallower gas appraisal lateral that could become a production well.
The PV12 exploration target is the Arumbera sandstone at an anticipated vertical depth of 3,560 m. The well will be drilled to a total vertical depth of 3,980 m—the deepest to be executed in the Amadeus basin. The target interval is also the gas-producing zone at Central’s Dingo gas field, about 120 km to the east.
The well will be deviated at up to a 45° angle in the target zone to increase the exposure to potential formation fractures. The well is estimated to reach the exploration target in early June.
If the PV12 deep exploration objective is unsuccessful, the well will be plugged and side-tracked to test the shallower Pacoota sandstone (1,770 m depth), with the potential to become a production well.
The appraisal is designed as a deviated well extending up to 1,000 m within the Pacoota sandstone, which is the current producing zone for Palm Valley field. The lateral design is similar to the PV13 appraisal well drilled in 2019, which had a lateral extension of only 300 m.
‘We have worked hard over the past year to lay the groundwork for the current two-well exploration program and three sub-salt exploration wells next year, giving us a total of 5 exploration wells over the next 18 months,” said Leon Devaney, managing director and chief executive officer.
The company is looking for opportunities to expand the drilling program to include an oil exploration well at Mamlambo and gas appraisal wells in the Mereenie stairway, he continued.
Drilling & Production Quick Takes
Libra Consortium begins production at Mero field Guanabara FPSO
Petrobras has started producing oil and natural gas through the Guanabara floating production, storage, and offloading vessel (FPSO) in Mero field, offshore Brazil.
The project is the first development phase of Mero field in the Libra block, more than 150 km off the coast of Rio de Janeiro, in the presalt area of the Santos basin. Mero is part of the Libra production sharing contract, signed in Dec 2013. Final investment decision on Mero-1 was made in 2018.
Guanabara has an installed capacity to process 180,000 b/d of oil and 12 million cu m/day of natural gas with an initial six producing wells and seven injector wells connected to the field. It’s the first of four production systems (Mero-2, Mero-3, Mero-4, all under construction) of equivalent capacity planned for the field with production start-ups between 2023 and 2025.
Originally scheduled for start-up in fourth-quarter 2021, the operator delayed project start to first-quarter 2022 as the FPSO was being converted in China and the COVID-19 pandemic caused a delay in construction. Peak production is expected by end 2022. Mero field has been in pre-production since 2017 with the 50,000 b/d of oil Pioneiro de Libra FPSO.
Built and operated by Modec, the unit lies in water depths that reach 1,930 m.
Petrobras is operator at Mero with 38.6% interest. Partners are Shell Brasil with 19.3%, TotalEnergies 19.3%, CNPC 9.65%, CNOOC Ltd. 9.65%, and PPSA 3.5%.
CNOOC adds production from two project starts
CNOOC Ltd. started production from Luda 5-2 oilfield north Phase I and Kenli 6-1 oilfield 4-1 block.
The Luda 5-2 north phase I project (operated, 100%) lies in Liaodong Bay of Bohai Sea, with average water depth of about 32 m. The project is utilizing existing processing infrastructure of Suizhong 36-1 oilfield and includes a new-build thermal recovery wellhead platform and production platform. A total of 28 development wells are planned, including 26 production wells and 2 water source wells. The project is expected to reach peak production of about 8,200 b/d of crude oil in 2024.
The Kenli 6-1 4-1 block development project (operated, 100%) lies in south Bohai Sea, with average water depth of about 17 m. The project utilizes the existing processing infrastructure of Bozhong 34-9 oilfield. A total of 12 development wells are planned, including 7 production wells and 5 water injection wells. The field is expected to reach peak production of about 4,000 b/d of crude oil in 2022.
Perenco starts production at Litznzi, Congo
Perenco Co. started production at the Litznzi infill drilling program, Congo, according to an Apr. 25 release from indirect partner PetroNor E&P ASA.
Two wells have been put on production; well #1 (injector) is flowing for a cleanup period producing some oil and mostly water as expected, well #2 (producer) was put on production Apr. 14 and produced above expectation for the first 8 days with an average 3,368 b/d, raising the average gross PNGF production to about 25,000 b/d for the period (4,207 b/d net).
The third well has been drilled to planned total depth and the operator is currently preparing to run open hole logs. The infill drilling program on PNGF Sud commenced in November 2021 with the spudding of the first of four wells on Litanzi as part of a total drilling program of 17 infill and development wells across four fields in the license area.
Perenco is operator at PNGF Sud (40%) with partners Hemla E&P Congo (20%, of which PetroNor holds 16.83%), SNPC (15%), Continent Congo SA (10%), Africa Oil & Gas Corp. (10%), and Petro Congo (5%).
Strike Energy’s Waylering flow test exceeds expectations
Strike Energy Ltd. has suspended Waylering-5 to ready the well for final completion as a producer after a 21-day flow test exceeded expectations.
The test of Waylering gas field onshore Western Australia in the North Perth basin produced a choke coefficient peak rate of 75 MMcfd on a 72/64-in. choke with a flowing well head pressure (FWHP) of 2,599 psi.
The company is investigating minor changes to production infrastructure design to increase throughput to 35 MMcfd of gas with potential to produce up to 42 terajoules/day without upscaling major components.
Strike said the flow of gas, comingled from the A and B sands, was limited by the testing package on site and is the third highest test rate recorded in the Perth basin.
Stabilized flows of 67 MMcfd with an FWHP of 2,634 psi were measured on the same setting when diverted through the separator to measure liquid hydrocarbon streams of 8 bbl per MMcf of gas.
The comingled flow followed individual tests of the A and B sands.
The A-sand flowed at a maximum recorded rate of 59 MMcfd with stabilized rates of 52 MMcfd maintained for over 24 hours at an FWHP of 2,557 psi through a 64/64-in. choke.
The B-sand flowed at a maximum recorded rate of 32 MMcfd with stabilized rates of 28 MMcfd over 24 hours at FWHP of 2,175 psi through a 48/64-in. choke.
Both sands are of high quality with negligible impurities and condensate ratios of 9 bbl per MMcf of gas (A-sand) and 6 bbl per MMcf of gas (B-sand). The light oil had API values of 39-47 degrees.
Waylering-6 appraisal well is currently drilling at 2,130 m.
Waylering lies in permit EP447. Strike is operator with 55% interest. Talon Energy has 45%.
PROCESSING Quick Takes
TotalEnergies’ Normandy integrated platform now producing SAF
TotalEnergies SE has started production of sustainable aviation fuel (SAF) from a new plant at its 253,000-b/d integrated Normandy refining and petrochemicals platform in Gonfreville l’Orcher, France (OGJ Online, June 4, 2021).
The plant, which officially began producing SAF in March, complements biojet fuel production from TotalEnergies’ La Mède biorefinery—France’s first—at Bouches-du-Rhône on the French Riviera, as well as the Oudalle plant in Seine-Maritime, near Le Havre, the operator said in a release.
While the company did not reveal details regarding the volume of SAF currently produced at the Normandy platform, the operator did confirm output from the new plant—all of which is destined for French airports—will enable the company to meet increased demand in line with France’s recently enacted legislation as of Jan. 1 that calls for aircraft to use at least 1% SAF to help incrementally replace fossil-based jet fuel as part of the country’s broader commitment of addressing climate change through 2050.
TotalEnergies additionally confirmed it remains on track by 2024 to begin production of SAF from a new biorefinery under construction as part of the operator’s Project Galaxie repurposing of its former 101,000-b/d Grandpuits refinery at Seine-et-Marne near Melun, southeast of Paris.
The company previously said it also expects to complete by 2024 its more than €500-million conversion of the entire Grandpuits site into a zero-crude industrial platform (OGJ Online, Sept. 28, 2020).
“By announcing the start-up of SAF production at [Normandy], we are responding to strong demand from the aviation industry to reduce its carbon footprint. We are also confirming our commitment to support customers by offering innovative solutions to reduce their emissions,” said Bernard Pinatel, TotalEnergies’ president of refining and chemicals.
Last year, TotalEnergies said production of biofuels—which reduce carbon emissions by at least 50% compared to their fossil equivalents—plays an important role in its broader net-zero strategy to meet carbon neutrality, as well as in France’s roadmap for incorporating 2% of SAF by 2025, 5% by 2030, and 50% by 2050 as part of the broader global energy transition (OGJ Online, Dec. 6, 2021).
TotalEnergies began supplying SAF to French aircraft operators beginning in 2021, according to the operator’s website.
ADNOC inks deal for stake in Borealis
Abu Dhabi National Oil Co. (ADNOC) has entered an agreement to purchase Mubadala Investment Co.’s (Mubadala) ownership stake in Borealis AG, a European leader in production of base chemicals, fertilizers, and mechanical recycling of plastics.
As part of the late-April agreement—which remains subject to customary closing conditions and regulatory approvals—ADNOC will acquire Mubadala’s entire 25% interest in Borealis to become co-owner alongside majority shareholder OMV AG (75%), ADNOC said.
The proposed transaction comes as part of ADNOC’s broader program to expand its international footprint in the growing chemicals and petrochemical sector.
In addition to supporting acceleration of its global downstream and industrial growth program, the planned acquisition would further expand ADNOC’s existing partnership with Borealis, with whom it shares joint ownership of Abu Dhabi Polymers Co. Ltd. (Borouge).
The acquisition stake in Borealis also would complement ADNOC’s global strategic growth and investment approach, reinforcing its aim to serve as a catalyst for responsible, sustainable investment and value creation for Abu Dhabi and the UAE as it continues its transformation into an integrated, global energy operator, the company said.
Details regarding a timeframe for when the proposed transaction might be completed were not revealed.
ADNOC’s ongoing expansion initiatives in the petrochemicals sector currently includes the newly commissioned fifth polypropylene plant (PP5) at Borouge’s integrated polyolefins complex in Ruwais, about 250 km west of Abu Dhabi City, UAE. Borouge also recently let a series of major contracts for its November 2021-approved fourth expansion of the site’s integrated polyolefins complex that—scheduled to become operational by yearend 2025—will boost the operator’s Ruwais sitewide production capacity of polyolefins—including polyethylene and polypropylene—to 6.4 million tonnes/year to make it the largest single-site polyolefins complex in the world.
Following startup, ADNOC previously said the Borouge 4 plant also will enable the next phase of growth of Ruwais’ broader industrial complex by allowing the Borouge partnership to supply feedstock to the TA’ZIZ Industrial Chemicals Zone, one of three special industrial ecosystems under development by ADNOC and UAE’s ADQ that specifically aims to anchor a host of petrochemical projects by both domestic and outside investors.
TRANSPORTATION Quick Takes
Whistler takes expansion FID
Whistler Pipeline LLC has reached a final investment decision to move forward with expansion of the Whistler natural gas pipeline after having secured sufficient firm transportation agreements with shippers.
The expansion will increase the mainline transport capacity to Texas Gulf Coast markets from the Permian basin to 2.5 bcfd from 2 bcfd through the planned installation of three new compressor stations. The expansion is expected to be in service in September 2023.
Whistler is a 450-mile, 42-in. OD transmission line running between the Waha hub and Agua Dulce and an 85-mile, 36-in. OD lateral providing connectivity to the Midland basin.
Whistler is owned by MPLX LP, WhiteWater Midstream, and a joint venture of Stonepeak Infrastructure Partners and West Texas Gas Inc.
QatarEnergy awards final major North Field East project EPC contract
QatarEnergy has let an engineering, procurement, and construction (EPC) contract for the North Field Expansion project.
A joint venture between Técnicas Reunidas SA (TR) and Wison Engineering has been selected as EPC contractor and was awarded a lump-sum contract for the expansion of the sulfur handling, storage, and loading infrastructure within Ras Laffan Industrial City. The TR-Wison joint venture will manage the detailed engineering work from Qatar.
The infrastructure will support the North Field East (NFE) LNG expansion project’s four new LNG trains, which are scheduled to start by yearend 2025. The contract will include an option for further expansion to support sulfur production for the two additional LNG trains of the North Field South (NFS) project, and infrastructure to support future additional LNG trains.
The only remaining major EPC contract for the delivery of the North Field Expansion project, comprising NFE and NFS projects, is one for NFS’s two onshore processing and liquefaction trains, which is expected to be awarded by yearend.
When completed, the NFE and NFS projects will increase Qatar’s LNG production capacity to 126 million tpy by 2027 from the current 77 million tpy.
NextDecade to sell Rio Grande LNG output to ENGIE
NextDecade Corp., Houston, executed a 15-year contract with ENGIE SA to supply LNG from its 27-million tonne/year (tpy) Rio Grande LNG liquefaction plant in Brownsville, Tex.
ENGIE will purchase 1.75 million tpy of LNG on a free-on-board basis from NextDecade’s first two trains of Rio Grande LNG.
NextDecade anticipates making a positive final investment decision (FID) on at least two Rio Grande trains (Phase 1, 11 million tpy) in second-half 2022, with FIDs of its remaining three trains to follow. The first train would start commercial operations as early as 2026.
NextDecade also has agreements in place with Shell PLC, Guangdong Energy Group Natural Gas, and ENN LNG (Singapore) Pte. Ltd.
Venture Global authorized to commission first six Calcasieu Pass liquefaction blocks
Venture Global Calcasieu Pass LLC has received US Federal Energy Regulatory Commission (FERC) authorization to commission the first six of nine two-train liquefaction blocks at its 10-million tonne/year (tpy) Calcasieu Pass LNG plant in Cameron Parish, La. In addition to its 18 0.6-million tpy liquefaction trains, the Calcasieu Pass plant includes an onsite natural gas-fired power plant, three pretreatment trains, two 203,500-cu m LNG storage tanks, and two berths capable of loading LNG vessels as large as 185,000 cu m.
FERC began granting commissioning authorization for Blocks 2-6 in November 2021 and issued its last authorization Mar. 30. With only three blocks left to authorize, and given the pace at which the terminal has received FERC approvals to commission, Calcasieu Pass could reach full capacity by third-quarter 2022, according to the US Energy Information Administration.
Venture Global loaded its first commissioning cargo from the plant earlier this year. The tanker Yiannis, chartered by JERA Global Markets Pte. Ltd., delivered the LNG to the Netherlands and France.
Calcasieu Pass receives its feedgas through Venture Global’s 24-mile, 42-in. OD TransCameron pipeline (1.9 bcfd), which has interconnections with TC Energy Corp.’s ANR pipeline, Enbridge Inc.’s TETCO pipeline, and EnLink Midstream Co.’s Bridgeline pipeline.