OGJ Newsletter
GENERAL INTEREST Quick Takes
Equinor gets green light for Hywind Tampen development
Equinor and its partners in the Snorre and Gullfaks developments received approval from Norwegian authorities for plans submitted in October 2019 for the development and operation of the Hywind Tampen offshore wind farm project in the Norwegian North Sea (OGJ Online, Oct. 11, 2019).
The oil and gas platforms at these projects will be the first ever powered by a floating offshore wind farm. Hywind Tampen will lie 140 km offshore in 260-300 m of water between the Snorre and Gullfaks platforms and will consist of 11 wind turbines based on the Equinor’s Hywind technology. The 8-Mw turbines will have a total capacity of 88 Mw, capable of meeting about 35% of the annual power demand of the five Snorre A and B and Gullfaks A, B, and C platforms. Reducing the use of gas turbines on the fields helps cut carbon dioxide emissions by more than 200,000 tonnes/year, the company said.
Operated from Equinor’s offices in Bergen, Hywind Tampen is scheduled for start-up at the end of 2022.
Brazil’s ANP suspends bid round
Brazil’s National Petroleum, Natural Gas, and Biofuels Agency (ANP) confirmed Apr. 1 the suspension of its 17th oil and gas bid round which was scheduled for this year.
The agency complied with the determination of the Ministry of Mines and Energy which requested the temporary suspension, specifically those related to the publication of the pre-public notice and the draft contract, in view of the current economic and resulting from the COVID-19 pandemic.
The National Energy Policy Council (CNPE) will define a new schedule for the bidding process, which will be submitted for evaluation by its members.
Expected to be on offer are 128 blocks in the Maritime Sedimentary basins of Pará-Maranhão, Potiguar, Campos, Santos, and Pelotas.
Rosneft halts Venezuelan operations
Russian-state Rosneft has terminated its operations in Venezuela, selling its interest in Venezuelan businesses, including joint ventures Petromonagas, Petroperija, Boqueron, Petromiranda, and Petrovictoria, as well as oilfield services companies and commercial and trading operations. All assets and trading operations of Rosneft in Venezuela or connected with Venezuela will be disposed of, terminated, or liquidated.
Petromonagas, a joint venture between Rosneft (40%) and Petroleos de Venezuela SA (PDVSA), operates a 150,000-b/d heavy oil upgrader in the Orinoco oil belt. The site has been blending Orinoco bitumen with Mesa crude to produce Merey-grade crude.
Petromiranda, another 40-60 Rosneft-PDVSA JV, projected production as high as 450,000 b/d of extra-heavy crude from the Junin-6 section of the Orinoco belt. More recent production was closer to 5,000 b/d. Junin-6 contains as much as 500 billion bbl of oil (OGJ Online, Apr. 16, 2010).
Petrovictoria focused on developing the Carabobo-2/4 Orinoco project. Rosneft (40%) and PDVSA (60%) began pilot production at Carabobo-2 in 2017 (OGJ Online, June 15, 2017).
Rosneft also owned 40% of the Petroperija and 26.67% of the Boqueron oil production projects.
Exploration & Development Quick Takes
Apache, Total encounter distinct fan system with second Block 58 discovery
Apache Corp. and partner Total SA have identified 79 m of net oil and gas condensate pay offshore Suriname at the Sapakara West-1 well on Block 58. The discovery is the second ‘significant’ oil discovery on the block following the Maka Central-1 discovery in January, Apache said Apr. 2 (OGJ Online, Jan. 7, 2020). The partners will conduct additional tests to appraise the resources and productivity of the reservoir.
Drilled by the Noble Sam Croft drilling facility to a depth of 6,300 m, the well encountered oil and gas condensate in two distinct upper Cretaceous intervals (Campanian, Santonian).
The third and fourth exploration well locations in Block 58 have been identified.
Preliminary fluid samples and test results indicate the shallower Campanian interval contains 13 m of net gas condensate and 30 m of net oil pay, with API oil gravities of 35-40 degrees. The deeper Santonian interval contains 36 m of net oil-bearing reservoir with API oil gravities of 40-45 degrees.
“Based on a conservative estimate of net pay across multiple fan systems, we have discovered another very substantial oil resource with the Sapakara West-1 well,” said John J. Christmann, Apache chief executive officer and president. “Importantly, our data indicates that the Sapakara West-1 well encountered a distinct fan system that is separate from the Maka Central-1 discovery we announced in January this year.”
Block 58 comprises 1.4 million acres and offers significant potential beyond the discoveries at Sapakara West and Maka Central. Apache has identified at least seven distinct play types and more than 50 prospects within the thermally mature play fairway.
Upon completion of operations at Sapakara West-1, the Sam Croft will move to the third prospect in Block 58, Kwaskwasi, which lies 10 km northwest of Sapakara West-1. The fourth exploration target is Keskesi, which will be drilled 20 km southeast of Sapakara West-1. Both will test oil-prone upper Cretaceous targets in the Campanian and Santonian intervals in reservoirs that appear to be independent from the Maka and Sapakara discoveries.
Apache is operator of Block 58 with 50%. Total holds the remaining 50%. Total will become operator of the block after the drilling of the fourth well (OGJ Online, Dec. 23, 2019).
Otto Energy mulls South Marsh Island F5 sidetrack
Otto Energy Ltd. and its Gulf of Mexico South Marsh Island 71 partner will temporarily abandon the F5 wellbore in a manner that allows for a possible sidetrack when uncertainty from the COVID-19 pandemic dissipates and a time where oil price volatility stabilizes.
Drilling operations on F5 were resumed Mar. 17 by Enterprise Offshore Drilling’s Enterprise 264 jackup. Surface casing shoe was tested at 3,610 ft measured depth (MD) and the well reached 8,505 ft MD (7,591 ft true vertical depth (TVD)) on Mar. 21.
The primary D5 sand target was penetrated within 50 ft of the predicted depth at 8,225 ft MD (7,330 ft TVD) and Log While Drilling (LWD) Triple Combo (Gamma Ray, Resistivity and Neutron Density) tools logged a total of 39 ft MD (36 ft TVD) net gas pay. While the F5 intersected a high quality D5 sand in this northernmost trap, it appears high on structure and has potentially faulted out the lowermost portion of the D5 sand at the F5 location. LWD data is insufficient to determine the extent intersected pay may potentially connect to a lower, thicker D5 reservoir sequence.
In addition to the D5 sand gas pay, the F5 well intersected 16 ft MD (12 ft TVD) net oil pay in the I3 sand and 25 ft MD (20 ft TVD) net oil pay in the J sand reservoirs. The result in these two sands verifies the extent of the I3 and J sand reserves as previously mapped and logged in the SM71 F1 well.
The acquired data will determine whether to side-track within the F5 fault block slightly down-dip and away from the fault at the current location in the D5 reservoir to encounter the full D5 reservoir section that may be missing in this location, or to step-out into the main producing fault block and commission an acceleration well in the I3, J, and D5 reservoir.
The joint venture has considered the uncertainty of continuing current operations due to the COVID-19 pandemic. In particular, a planned crew change would be required if the rig was to continue operations introducing heightened risk of operational interruptions during a critical phase.
Otto, through its wholly owned subsidiary Otto Energy LLC, holds a 50% working interest and a 40.625% net revenue interest in SM71. Byron Energy Ltd. is operator and holds the remaining interest.
Wintershall Norwegian Sea discovery could warrant tie-back
Wintershall Dea Norge AS and partners will consider a tie-back of an oil discovery on the Bergknapp (Toshi) prospect in the Norwegian Sea. Preliminary estimates place the size of the discovery at 4-15 million s cu m of recoverable oil equivalents.
Well 6406/3-10, the first exploration well in production license 836 S, was drilled about 8 km west of Maria field and 200 km north of Kristiansund to a vertical depth of 4,566 m subsea. It was terminated in the Are formation from the Early Jurassic Age. Water depth at the site is 313 m. The well was partially drilled by the West Mira drilling facility. It was then temporarily plugged before drilling was completed by the Scarabeo 8 drilling facility.
The primary exploration target for the well was to prove petroleum in reservoir rocks from the Early and Middle Jurassic (Ile and Tilje formations). The secondary exploration target was to prove petroleum in reservoir rocks from the Middle Jurrasic Age (Garn formation).
In the primary exploration target, the well encountered hydrocarbon-bearing sandstone layers totaling about 35 m in the Ile formation, with poor reservoir quality. The well encountered a total oil column of 120 m in the Tilje formation, with sandstone layers totaling about 75 m with poor to good reservoir quality. The oil-water contact was not encountered.
In the secondary exploration target, a total oil column of about 60 m was encountered in the Garn formation, with sandstone of poor to moderate reservoir quality. The oil-water contact was encountered at about 4,095 m subsea.
The well was not formation-tested, but data acquisition and sampling have been carried out.
Wintershall is operator of the license with 40%. Partners are Spirit Energy Norway AS 30% and DNO Norge AS 30%.
Drilling & Production Quick Takes
Marathon halts Bakken, Eagle Ford operations
Marathon Oil has cut $1.1 billion from its initial 2020 capital spending budget to $1.3 billion or less in response to market conditions. In February, the company budgeted $2.4 billion for the year, down 11% from 2019 levels (OGJ Online, Feb. 24, 2020). Capital spending for the year is now expected to be 50% below actual capital spending in 2019.
The revised budget includes halting second quarter fracturing operations in the Bakken and Eagle Ford, “before transitioning to a lower and more continuous drilling and completion program over the second half of 2020 in both basins,” the company said Apr. 8.
Previously, the company said it would fully suspend resource play exploration and Oklahoma activity. The company will now also suspend further drilling activity in the northern Delaware basin, “with only a limited number of wells to sales expected through the balance of the year,” it said.
Marathon Oil plans to provide a more comprehensive update to its revised 2020 business plan as part of its first quarter earnings release in May.
OMV suspends New Zealand drilling
OMV has suspended its drilling program in the offshore Taranaki basin off the west coast of the North Island of New Zealand.
The New Zealand Government deemed exploration drilling as not an essential service due to the COVID-19 Stage 4 alert lockdown, the company said.
The first well of the current program, Toutouwai-1, has been completed. The COSL Prospector semi-submersible rig has been stood down from the rest of the 2020 program.
The Maui-8 well was to be the next well drilled.
Additionally, the Maui A crestal infill re-development campaign has been suspended because it was considered too risky to manage shift changes involving a large international workforce.
Six wells had been planned for the Archer Emerald rig to extend the life of Maui gas field.
A maintenance program on the Pohokura offshore pipeline is continuing and will be completed by mid-April to ensure that gas to New Zealand industry is not compromised. This project was deemed an essential service.
UKOG files planning application for Isle of Wight appraisal well
UK Oil & Gas Plc (UKOG) filed a planning application with the Isle of Wight Council for appraisal drilling and flow testing of the Arreton oil discovery in Petroleum Exploration Development License (PEDL) 331, which extends over 200 sq km covering most of the southern half of the Isle of Wight. The application was expected to go live on Mar. 27.
The application details the planned construction, operation, and eventual decommissioning of a well site for the appraisal of hydrocarbons via a deviated borehole (A-3) plus a possible horizontal sidetrack off the mother borehole (A-3z), all to be undertaken within a temporary period of 3 years.
The Arreton conventional oil discovery, a geological analogue of Horse Hill oil field, contains three stacked Jurassic oil pools containing a calculated 127 million bbl aggregate gross P50 oil in place as calculated by Xodus. UKOG’s net share of associated mid-case recoverable contingent resource volumes were stated by Xodus to be a material 14.9 million bbl.
A-3 is envisaged to duplicate A-1 and A-2 discoveries drilled by BP and the Gas Council (now Spirit Energy) in 1952 and 1974, respectively. Should short term flow testing of A-3 indicate likely commercial viability, an A-3z horizontal sidetrack would be drilled and put on extended well test to assess longer-term flow performance.
UKOG holds 95% operated interest in PEDL 331.
PROCESSING Quick Takes
HollyFrontier lets contract for Navajo refinery unit
HollyFrontier Corp. has let a contract to KP Engineering LP (KPE) to provide a series of services for construction of a previously announced new renewable diesel unit (RDU) at its 100,000-b/d Navajo refinery in Artesia, NM (OGJ Online, Nov. 19, 2019).
As part of the contract with HollyFrontier subsidiary Artesia Renewable Diesel Co. LLC (ARDC), KPE will deliver engineering, procurement, and construction management (EPCm) for the on-site portion of the proposed RDU, the service provider said.
KPE did not disclose a value of the EPCm contract.
ARDC previously awarded a contract to Haldor Topsoe AS to license its proprietary HydroFlex technology, as well as supply basic engineering, proprietary equipment, catalysts, and technical services, for the new RDU, which comes as part of HollyFrontier’s expansion into renewable fuels (OGJ Online, Jan. 29, 2020).
Implementation of HydroFlex technology for the unit will enable the refinery to reduce its cost of compliance with US Environmental Protection Agency (EPA) mandates for how much biofuel must be blended into fuels sold in the US market by enabling production of clean, renewable diesel from all-renewable feedstocks.
Upon announcing the project in late 2019, HollyFrontier said the RDU will have a production capacity of about 125 million gal/year (9,000 b/d), allowing the refinery to process soybean oil and other renewable feedstocks into renewable diesel to help meet demand for low-carbon fuels while covering the cost of the operator’s annual EPA-regulated RIN purchase obligation under current market conditions.
HollyFrontier said it expects a total capital cost of $350 million for the RDU project, which will include corresponding rail infrastructure and storage tanks.
The RDU project is scheduled to be completed during first-quarter 2022.
On Apr. 8, the company cut its 2020 budget, but said Navajo refinery unit plans continue. Total consolidated capital expenditures for 2020 are expected to be $525-625 million, down 15% from its previous guidance of $623-729 million due to current market conditions.
Parkland Fuel wrapping up Burnaby refinery turnaround
Parkland Fuel Corp. subsidiary Parkland Refining (BC) Ltd. is nearing completion of work activities related to the 2020 turnaround that began in February at its 55,000-b/d refinery on Burrard Inlet in North Burnaby, near North Vancouver, BC.
With the refinery’s startup sequence now under way, Parkland Refining expects about a 2-week process for the site to return to full operational capability when accounting for additional coronavirus (COVID-19) safety measures, Parkland Fuel said on Apr. 6.
Measures related to COVID-19 control required the operator to change processes and procedures in response to guidance from provincial health authorities, resulting in a decrease in the number of staff on site as well as lower productivity, the company said.
Started in early February and initially scheduled to last 6-9 weeks, the $60-million (Can.) 2020 major turnaround was to include works focused on the refinery’s crude unit, fluid catalytic cracker, and sulfur recovery unit, as well as preventative work on several other unidentified units, Parkland Refining told refinery neighbors in late 2019.
The turnaround also was to involve “proactive upgrades” to refinery safety systems and unidentified preliminary works to advance the site’s “green refining” capabilities.
At peak turnaround activity, Parkland Refining said about 550 contractors were to be on site during each shift.
Parkland Fuels disclosed no further details regarding specific projects to be executed during the turnaround or specific impacts COVID-19 safety measures had on the maintenance event’s original scope.
The Burnaby refinery processes light and synthetic Canadian crudes such as Edmonton Par 80% and Syncrude 20% into gasoline, diesel, jet fuel, asphalt, heating fuel, heavy fuel oil, butane, and propane for distribution throughout British Columbia.
Calgary-based Parkland Fuel purchased the Burnaby refinery and related downstream assets from Chevron Canada Ltd. in 2017 (OGJ Online, Apr. 20, 2017).
IOC reduces crude throughputs across Indian refining system
Indian Oil Corp. Ltd. has slashed crude oil throughputs at most of its refineries by 25-30% amid sharply reduced demand for finished petroleum products in the wake of the coronavirus (COVID-19) outbreak across India.
Despite currently reduced rates, increased output of petroleum products from the refineries a week earlier has helped the company build up its stocks in bulk-storage locations to help meet supply needs once India’s countrywide lockdown is lifted and demand resumes, IOC said in a release.
The operator said it will continue to monitor changing market scenarios and initiate actions to adapt its business accordingly.
While the COVID-19 outbreak has reduced India’s demand for products such as gasoline, diesel, fuel oil, bitumen, and jet fuel, domestic demand for LPG cooking gas has increased. To meet the country’s rising LPG demand, IOC said it is taking steps to increase LPG production from its major refineries by optimizing operations, including works to improve LPG yields in LPG-producing units like fluid catalytic crackers and Indmax units.
Despite the many constraints to operations resulting from the current COVID-19 crisis, IOC reassured customers it remains committed to ensuring fuel availability to customers and emergency services while maintaining all necessary precautionary measures.
The operator disclosed no details regarding the specific refineries operating at reduced crude rates nor their current rates of throughputs.
With an overall group refining capacity of more than 80.7 million tonnes/year—the largest share among domestic refining companies—IOC controls 11 of India’s 23 refineries directly and via subsidiaries to account for a 32.36% share of total national refining capacity, according to the company’s website.
TRANSPORTATION Quick Takes
BP declares Greater Tortue Ahmeyim FLNG force majeure
BP Mauritania Investments Ltd. declared force majeure to Gimi MS Corp., a subsidiary of Golar LNG Ltd., stating that due to the recent outbreak of COVID-19, BP could not receive floating LNG plant Gimi by its target connection date in 2022. Gimi was to have been used to develop the Greater Tortue Ahmeyim project offshore Mauritania and Senegal.
BP estimates that the consequential delay caused by the claimed force majeure event is on the order of 1 year and that it is not currently possible to mitigate or shorten this delay. Golar has asked BP to clarify how a force majeure event discovered as recently as end-March 2020 could immediately impact the schedule by an estimated 1 year.
Golar said that it is engaging in clarification and an active dialogue with BP to establish the duration of the delay and the extent to which it has been caused by the claimed force majeure event. In anticipation of a potential delay, however, Golar has started discussions with its main building contractor, Keppel Shipyard Ltd., to reschedule activities to reduce and reprofile its capital spending commitments for 2020-21.
BP let contracts to McDermott International Inc. and Baker Hughes for subsea umbilicals, risers, and flowlines and subsea production system equipment at Greater Tortue Ahmeyim. McDermott planned to use its upgraded Amazon vessel, DLV 2000, North Ocean 102, and third-party vessels to support installation scheduled to begin late-2020 (OGJ Online, Mar. 11, 2019).
Algeria puts GR7 natural gas pipeline in service
Algerian-state Sonatrach has completed line fill of its new 48-in. OD GR7 natural gas pipeline between El Menia and Hassi R’mel, Algeria. GR7 extends Sonatrach’s GR5 line by 344 km, moving gas from Hassi Mouina South and North fields and Hassi Ba Hamou fields to the national hub (CNDG) at Hassi R’mel.
GR7’s 4-billion cu m/year (bcmy) capacity will allow expansion of GR5 between Reggane and Hassi R’mel to 13 bcmy.
Algeria-based Cosider Canalisations SPA and Enterprise Nationale de Canalisations built the pipeline, with linepipe manufactured by EPE Alfapipe SPA, another Algerian company.
Statoil AS performed exploration and appraisal drilling on Hassi Mouina in 2007, testing natural gas in Devonian sandstones (OGJ Online, June 25, 2007). Hassi Mouina is in the western Sahara.