GENERAL INTEREST Quick Takes
Kistos to acquire Tulip Oil Netherlands
Kistos PLC has agreed to acquire the entire issued and outstanding share capital of Tulip Oil Netherlands BV from Tulip Oil Holding BV.
Tulip Oil Netherlands is operator (60%) in Q10-A offshore gas field with interests in other Dutch North Sea fields including Q10-B, Q11-B, and M10/M11 discoveries, as well as other exploration and appraisal projects.
Q10-A field has 2P reserves of 19.5 MMboe and generated total net production of 5,470 boe/d in 2020. Q10-A is reliant on solar and wind power. Its carbon emissions are below the North Sea average of 21 kg CO2/boe.
Total upfront consideration for the acquisition is roughly $263 million through a combination of cash, assumption by Kistos of an existing bond instrument issued by TONO, issue of a new debt instrument, and issue to Tulip of equity in Kistos. Contingent consideration of up to $195 million is payable on certain development milestones.
Upon completion of the deal, subject to conditions, Tulip Oil will become a shareholder and debtholder of Kistos and will continue to be a 90% shareholder in Rhein Petroleum.
Kistos is a closed-ended investment company established to acquire and manage energy sector companies or businesses. Upon completion of the acquisition, Kistos expects to cease being an investing company and instead become a trading company.
EOG expects oil production to maintain Q4 rate
EOG Resources Inc., Houston, set a 2021 capital plan of $3.7-4.1 billion and anticipates it will maintain oil production at the fourth-quarter 2020 rate.
The plan maintains 2021 crude oil volumes of 434,000-446,000 bo/d. There are no plans to increase capital expenditures or grow production volumes in the year, even in a higher commodity price environment, the company said Feb. 25.
First-quarter 2021 capex is guided at $900 million to $1.1 billion. Crude oil volumes of 419,600-430,600 bo/d are expected in the quarter.
For the year, the company expects to complete about 500 net wells focused on Delaware basin, Eagle Ford, and Powder River basin acreage.
Total production for fourth-quarter 2020 came in at 801,500 boe/d with oil volumes of 444,800 b/d. Capex for the fourth quarter was $829 million.
PNG’s highland provinces agree on benefits split
The provincial governments of Papua New Guinea’s Southern Highlands and Hela provinces signed an agreement for the distribution of benefits emanating from the ExxonMobil-operated PNG LNG project.
The division of benefits has been unsettled for 13 years since the project was sanctioned by the Umbrella Benefit Sharing Agreement (UBSA) in 2009 as there had been no distribution framework.
The UBSA saw all benefits signed off to the Southern Highlands province with the proviso that, as and when Hela region gained provincial status, the benefits from PNG LNG would be divided on equable terms. At that time the Hela region was part of the Southern Highlands jurisdiction and did not become a separate province until 2012.
This memorandum of agreement follows a formula worked out by the PNG government-owned Mineral Resource Development Co. and stipulates that benefits from oil and gas fields in the Southern Highlands will be split 60% to the Southern Highlands government and 40% to Hela government. Likewise, benefits for oil and gas fields in Hela province will be split 60% to Hela and 40% to Southern Highlands.
Benefits include royalties and development levies from various development licenses.
NEO to acquire North Sea portfolio from ExxonMobil
NEO Energy has agreed to acquire a portfolio of non-operated North Sea oil and gas assets from ExxonMobil. Following completion, NEO expects proforma 2021 production to be 70,000 boe/d and to grow organically to more than 80,000 boe/d in 2024 through ongoing field developments.
The acquired portfolio consists of 21 assets, including 14 fields and several infrastructure positions. The fields are divided into the following hubs: Gannet cluster (50%), Elgin-Franklin fields (4.38%), Shearwater area (including Fram, Starling, Merganser, Scoter, 44%-72%), Penguins redevelopment (50%), Nelson (21.23%), and ETAP (Mirren, Madoes, 21-25%).
The agreement is valued at more than $1 billion. Additional contingent considerations of $300 million are possible based on commodity prices. The transaction, subject to approvals from relevant authorities and regulatory consents, is expected to complete by mid-2021.
The acquired fields are operated by Shell, BP, and Total. NEO will become Shell’s largest partner in the UK Central and Northern North Sea.
Exploration & Development Quick Takes
Equinor makes oil discovery near Johan Castberg field
Equinor Energy AS and partners will evaluate a recent Barents Sea oil discovery with a view toward a possible tie-in to Johan Castberg field. Preliminary estimates place the size of the discovery in production license (PL) 532 at 5-8 million std cu m (31-50 million bbl) of recoverable oil.
Well 7220/7-4, the first of four planned Barents Sea exploration wells for the company this year (as operator or partner), was drilled about 10 km southwest of the 7220/8-1 (Skrugard) discovery on Johan Castberg field and 210 km northwest of Hammerfest. Water depth at the site is 351 m.
The objective of the well was to prove petroleum in reservoir rocks from the Middle to Early Jurassic age (Stø and Nordmela formations).
The exploration well—the 11th in the license—was drilled by the Transocean Enabler harsh-environment semisubmersible drilling rig to a vertical depth of 2,080 m subsea. It was terminated in the Tubåen formation from the Early Jurassic age. The well encountered a 109 m oil column in Stø and Nordmela formations, of which about 90 m were sandstone of moderate to good reservoir quality. Oil-water contact was encountered 1,897 m subsea, but the expected gas cap was not encountered. The well was not formation-tested, but extensive data acquisition and sampling were conducted.
The well will be permanently plugged, and the drilling facility will continue to drill development wells in connection with development of Johan Castberg.
Equinor Energy AS is operator of the license (50%) with partners Petoro AS (20%) and Vår Energi AS (30%).
APA terminates Suriname well due to high pressure
APA Corp. terminated Keskesi East-1 drilling operations offshore Suriname before reaching Neocomian targets due to higher than expected pressure and completed transfer of Block 58 operatorship to Total SA following release of the Noble Sam Croft drillship.
The well had discovered oil, volatile oil, and condensate in the Upper Cretaceous-aged Campanian and Santonian intervals and, subsequently, continued drilling toward deeper Neocomian-aged targets (OGJ Online, Jan. 14, 2021). The well encountered hydrocarbons in the Lower Cretaceous interval and a carbonate depositional system above the top Neocomian target, both of which help to validate the geologic models. The data does not reveal specific information about the Neocomian targets themselves, the company said.
As drilling progressed, the well encountered substantial pressure increases that APA determined could ultimately exceed capabilities of the wellbore design and pressure control equipment. Consequently, partners decided to conclude drilling operations.
Information gathered from the well will be used to design a wellbore and drilling program that will ensure a safe test of the deep Neocomian targets in future exploration and/or appraisal operations, the company said.
APA transferred operatorship of Block 58 to Total on Jan. 1, 2021, but continued to operate the Keskesi exploration well until release of the drillship. Total and APA each have 50% interest in the block (OGJ Online, Dec. 23, 2019).
NZOG releases last South Island exploration permit
The last offshore exploration permit off the east coast of the South Island of New Zealand has been relinquished leaving the country’s offshore petroleum exploration industry confined to the Taranaki basin off the west coast of the North Island.
New Zealand Oil & Gas Ltd. (NZOG) walked away from its final permit, marking the end of an era for exploration off the South Island without a commercial success.
The permit, 55794 (Toroa), covered 5000 sq km in the Great South basin to the east of Stewart Island.
The relinquishment follows a number of other withdrawals, including OMV and Beach Energy, from the great South and Canterbury basins in the last few months.
NZOG said the relinquishment was made for a number of reasons, including adverse regulatory settings for offshore exploration, the failure of wells in neighboring permits to make any commercial discoveries thus downgrading the region, and the effect of the COVID-19 pandemic on drilling costs and rig availability.
The company said it had exhausted all avenues to find potential partners to farm into the acreage and share the cost of a drilling program.
New Zealand’s oil and gas industry is once again limited to the areas surrounding the known Taranaki fields at a time when the country’s gas supplies are dwindling.
Shell completes top hole batch drilling at Malikai
Sabah Shell Petroleum Co. Ltd. has advanced development at Malikai with completion of a top-hole batch drilling campaign with riserless mud recovery (RMR) performed by Enhanced Drilling for five wells in phase two of the project, 100 km off the west coast of Sabah, Malaysia, in about 500 m of water, the service provider said Mar. 10.
RMR is a dual gradient top-hole drilling technology that allows drilling of the riserless section with full volume control and returns of the drilling fluid back to the rig. For Malikai Phase 2 drilling, the system reduced the amount of casing strings and enabled volume control and good hole cleaning in the 17 ½-in. section.
Malikai comprises two main reservoirs, Kinarut and Kamunsu-2, with 60,000 b/d peak annual production. The project involves the drilling of additional oil producing wells and water injection wells to enhance Malikai’s expected recoverable oil volumes and is expected to contribute to Malikai’s production in second-quarter 2021 (OGJ Online, Jan. 13, 2020).
Shell is operator (35%) with partners ConocoPhillips (35%) and Petronas Carigali (30%).
Drilling & Production Quick Takes
Earthstone begins 2021 drilling program in Midland County
Earthstone Energy Inc., The Woodlands, Tex., recently commenced its 2021 drilling program with the deployment of a rig in Midland County, Tex., with an expected 2021 capital expenditure budget of $90-100 million. Production guidance for the year is 19,500-21,000 boe/d (52-54% oil).
After drilling on a three-well pad in the Hamman project, the company expects to drill a four-well pad on the recently acquired Independence Resources Management (IRM) Spanish Pearl project. The deal to acquire IRM for $185.9 million closed Jan. 7. The company then plans to move the rig to Upton County to drill 10-11 wells.
Overall, the company anticipates drilling 16 gross/14.8 net operated wells and spudding an additional 5 gross/3.7 net operated wells during 2021.
The company recently completed 5 gross/3.7 net wells in Upton County and anticipates turning the wells to sales before the end of March. In 2021, a total of 16 gross/13.5 net operated wells are expected to complete and turn to sales.
In fourth-quarter 2020, the company produced an average 14,809 boe/d. Full year 2020 average production was 15,276 boe/d with capital expenditures of $66.8 million comprised primarily of drilling and completion costs.
CNOOC starts Caofeidian 6-4 oil field production
CNOOC Ltd. started production from Caofeidian 6-4 oil field, offshore Bohai Bay, China.
The project, midwest of Bohai in 20 m average water depth, utilizes existing processing facilities of Nanpu 35-2 and Qinhuangdao 32-6 oil fields in addition to a new central platform.
A total of 42 development wells are planned, including 30 production wells, 12 water injection wells, and water source wells. The project is expected to reach peak production of about 15,000 b/d in 2023.
CNOOC is operator of the field with 100% interest.
Santos secures rig for Bedout subbasin wildcats near Dorado
A joint venture of Santos Ltd. and Carnarvon Petroleum Ltd. has contracted the Noble Tom Prosser jack up rig to drill wildcat wells Pavo-1 and Apus-1 near the group’s previous oil and gas discovery at Dorado field off Western Australia.
The drilling program will begin late this year with Pavo-1 and immediately followed by Apus-1.
If successful, both prospects have the potential to materially increase the aggregate development resource for Dorado field with tiebacks to the Dorado facilities, Carnarvon said.
Pavo-1 will target a potential 100 MMboe while Apus has triple the potential with 307 MMboe.
The Noble Tom Prosser was previously used by the JV in 2019 to drill the successful Dorado-2 and Dorado-3 appraisals. Dorado was discovered in 2018 and has an estimated resource of at least 150 million b/o.
The Dorado development program is in a pre-front-end engineering and design stage with facilities being designed for production of 75,000-100,000 b/d of oil.
PROCESSING Quick Takes
Esso, BHP sign deal to extract, reuse Bass Strait CO2
The Esso Australia-BHP Gippsland joint venture has signed an agreement with Air Liquide Australia to extract and reuse carbon dioxide (CO2) from gas produced from Bass Strait gas fields.
Under the terms of the long-term agreement, Air Liquide will build, own, and operate a new CO2 processing and purification facility adjacent to the Esso-BHP natural gas processing plants at Longford, near Sale in Victoria.
Esso-BHP will construct facilities at its Longford gas conditioning plant to enable it to transfer CO2 directly to the proposed Air Liquide plant. Air Liquide will then purify the CO2 to food and beverage quality which will be sold to Australian businesses.
Construction of the 65,000 tonnes/year CO2 processing plant is expected to begin later this year.
Commercial terms were not disclosed.
Pertamina-Rosneft JV lets contract for Tuban complex
Pertamina Rosneft Pengolahan dan Petrokimia (PT PRPP), a joint venture of PJSC Rosneft (45%) and Indonesian state-owned PT Pertamina (55%), has let a contract to Royal Dutch Shell Ltd.’s Shell Catalysts & Technologies (SC&T) to provide technology licensing and basic engineering services for new processing units at PT PRPP’s grassroots integrated oil refinery and petrochemical complex in Tuban, East Java, Indonesia (OGJ Online, Oct. 29, 2019).
As part of the contract, SC&T will deliver its proprietary OMEGA process for production of monoethylene glycol (MEG), as well as its distillate hydrotreating process for catalytic removal of sulfur and nitrogen, as well as hydrogenation of aromatics, from diesel fractions of certain crude oils, SC&T said on Feb. 24.
SC&T did not reveal a value of the contract.
Launched in 2016 and formally established in 2017, the PRPP JV is developing an integrated 300,000-b/d refinery and petrochemical complex at Tuban that, once in operation, will produce more than 1 million tonnes/year of ethylene and 1.3 million tpy of aromatic hydrocarbons (OGJ Online, Nov. 29, 2017).
The Tuban integrated complex specifically will produce 1.2 million tpy of polypropylene products, 1.3 million tpy of paraxylene, and 650,000 tpy of polyethylene, according to PT PRPP.
The complex is slated for startup during 2025, according to SC&T.
Methanex mothballs Waitara Valley methanol plant in NZ
Methanex Corp., Vancouver, will mothball its Waitara Valley methanol plant in the Taranaki region of the North Island of New Zealand.
The company says the decision has been made to close down the plant’s production because of its inability to secure sufficient gas supplies from the local fields offshore New Zealand. It is understood that there has been a decline in production from OMV’s Pohokura field as well as delays in new development drilling caused by the COVID-19 pandemic.
Methanex New Zealand’s managing director Dean Richardson said the decision was a disappointing for New Zealand as the company expects methanol demand to rebound and grow as global economic activity recovers.
Richardson said production would continue at the company’s two production trains at the Motunui plant, also in Taranaki; however, an organizational review has commenced in view of the lower production levels.
Methanex will place the Waitara Valley plant on a care and maintenance footing. Some activities will be retained, such as truck loading to supply the local market. The Waitara Valley facility will restart methanol production should gas become available, Richardson said.
Although not the first time the Waitara Valley plant has been mothballed, the current New Zealand government policy of not awarding any new offshore exploration licenses in the country is expected to lead to further decline in gas supplies.
Richardson said natural gas remains the cleanest viable feedstock to produce methanol on a commercial scale.
TRANSPORTATION Quick Takes
Valero, BlackRock, Navigator to build CCS pipeline, storage
Valero Energy Corp. and BlackRock Global Energy & Power Infrastructure Fund III are partnering with Navigator Energy Services to develop a 5-million tonne/year (tpy) carbon capture pipeline system. The project’s initial phase is expected to include more than 1,200 miles of new CO2 gathering and transportation and permanent storage. Pending third-party customer feedback, the companies could expand the system to transport and sequester up to 8 million tpy.
Valero expects to become an anchor shipper by securing most of the initial available system capacity. Navigator is expected to lead construction and operation of the system, with startup set for late 2024. Navigator will conduct an open season to secure additional commitments for capacity not booked by Valero.
Navigator will work with each counterparty to install or connect the applicable carbon capture equipment to the pipeline at various receipt points in Nebraska, Iowa, South Dakota, Minnesota, and Illinois. The proposed system plans to transport liquefied CO2 through 6- to 16-in. OD pipeline for delivery to a central sequestration site contemplated for south-central Illinois and will be expandable if demand warrants.
The open season will run through 12 p.m., Central Time, Apr. 30, 2021.
NextDecade completes EPC repricing for Rio Grande LNG
NextDecade Corp. and Bechtel Oil, Gas, and Chemicals Inc. have completed repricing of their lump-sum turnkey engineering, procurement, and construction (EPC) agreements for the first three trains at NextDecade’s 27-million tonne/year (tpy) Rio Grande LNG project in Brownsville, Tex.
The repricing had no impact on the overall cost of the project: $7 billion for two trains, $9.6 billion for three. The pricing is now valid until Dec. 31, 2021. NextDecade and Bechtel also agreed to extend the validity of the agreements until July 31, 2022.
NextDecade anticipates achieving a final investment decision on a minimum of two trains at Rio Grande LNG in 2021. The plant’s overall capacity is based on a planned five-train configuration (OGJ Online, July 15, 2020).
Novatek signs 15-year Arctic LNG 2 supply deal
PAO Novatek wholly owned subsidiary, Novatek Gas & Power Asia Pte. Ltd., and Shenergy Group have signed have a 15-year agreement for LNG to be produced from Novatek’s 19.8 million tonne/year (tpy) Arctic LNG 2 project. The agreement stipulates shipment of 3 million tpy of Arctic LNG 2’s production to terminals in China on a delivered ex-ship basis.
Arctic LNG 2 will use three 6.6-million tpy liquefaction trains installed on gravity-based platforms on Gydan Peninsula across the Gulf of Ob from Yamal LNG. The site will also produce 1.6 million tpy of condensate. Novatek expects to complete the project in 2024.
Gas and liquids will be sourced from Utrenneye field. As of yearend 2020, Novatek estimated Utrenneye field’s 2P reserves under petroleum resource management system terms at 1.4 trillion cu m of natural gas and 90 million tonnes of liquids.
Arctic 2 LNG project participants include: Novatek (60%), Total SE (10%), China National Petroleum Corp. (10%), China National Offshore Oil Corp. (10%), and the Japan Arctic LNG consortium of Mitsui & Co. and Japan Oil, Gas and Metals National Corp. (10%).